ITEM 1 - BUSINESS
Overview
We are a natural gas and petroleum exploitation, development and production company engaged in locating and developing hydrocarbon resources, primarily in the Rocky Mountain region. Our principal business strategy is to enhance stockholder value by generating and developing high-potential exploitation resources in these areas. Our principal business is the acquisition of leasehold interests in petroleum and natural gas rights, either directly or indirectly, and the exploitation and development of properties subject to these leases. We are currently focusing our operational efforts in the Riverbend Project located in the Uinta Basin of northeastern Utah, targeting the Green River, Wasatch, Mesaverde, Blackhawk, Mancos, Dakota and Morrison formations. As of December 31, 2012, we held interests in 156,285 gross (57,950 net) acres located in Utah and California. As of December 31, 2012, we held an interest in 133 gross (40 net to our interest) producing wells and three gross (one net) shut-in wells located on these properties.
We were incorporated on April 21, 1997 under the laws of the State of Nevada. We operated as a shell company until December 31, 1999.
2012 and Recent Highlights
Outlook
Due to the significant extended decline in the natural gas market and sustained low natural gas prices caused by excess production and stagnant growth in the demand for natural gas, we have not been able to recover our exploration and development costs as anticipated. As such, there is substantial doubt regarding our ability to generate sufficient cash flows from operations to fund our ongoing operations, and we currently anticipate that cash on hand and forecasted cash flows from operations will only be sufficient to fund cash requirements for working capital, including debt payment obligations, through the second quarter of 2013. We have not allocated any amounts to the 2013 capital budget. Our prior revolving credit facility matured in June 2012, at which time we repaid all of the outstanding borrowings thereunder. While we have attempted to secure a replacement facility, we have been unable to do so on acceptable terms and we are no longer actively in discussions to obtain a replacement facility. There can be no assurance that we will be able to adequately finance our operations or execute our existing short-term and long-term business plans, and our liquidity and results of operations are likely to be materially adversely affected if we are unable to generate sufficient operating cash flows, secure additional capital or otherwise pursue a strategic restructuring, refinancing or other transaction to provide us with additional liquidity. We have engaged a financial advisor to assist us in evaluating such potential strategic alternatives. It is possible these strategic alternatives will require us to make a pre-package, pre-arranged or other type of filing for protection under Chapter 11 of the U.S. Bankruptcy Code (or an involuntary petition for bankruptcy may be filed against us). These factors raise substantial doubt about our ability to continue as a going concern. For additional information regarding our current liquidity situation, please see “Liquidity and Capital Resources” in Item 7.-Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
Uinta Basin Joint Venture
On March 22, 2012, we closed a transaction (the “Uinta Basin Transaction”) whereby, pursuant to the Purchase and Sale Agreement (the “Purchase Agreement”) dated February 23, 2012, between our wholly-owned subsidiary, Gasco Production Company, and Wapiti Oil & Gas II, L.L.C. (“Wapiti”), and a Closing Agreement (the “Closing Agreement”) dated March 22, 2012 relating to the Purchase Agreement, we (i) sold to Wapiti an undivided 50% of our interest in certain of our Uinta Basin producing oil and gas assets for $18.0 million in cash and $1.19 million in the form of a promissory note receivable from Wapiti, which was repaid in full during the second quarter of 2012, and (ii) transferred to Wapiti an undivided 50% of our interest in certain of our Uinta Basin non-producing oil and gas assets in exchange for, among other agreements, Wapiti’s commitment to fund $30.0 million of the drilling and completion costs associated with the exploration and development of the subject assets.
As a part of the Uinta Basin Transaction, Gasco Production Company entered into a Development Agreement (the “Development Agreement”) with Wapiti, which includes terms and conditions of a drilling program agreed to by the parties.
Of Wapiti’s $30.0 million funding commitment, $15.0 million will be paid on our behalf, and we have agreed to provide an additional $7.5 million of drilling and completion costs. Accordingly, the total program will be $37.5 million. If we are not able to pay our share of the above costs, we may lose certain rights granted under the Development Agreement and related operating agreements, including the right to continue as operator or contract operator of the properties, the right to make proposals or elect to participate in operations under the Development Agreement or any operating agreement, the right to call, attend and vote at meetings of the operating committee, the right to transfer our interest in the properties and the joint venture, the right to acquire Wapiti’s interest in the properties under the right of first offer provisions of the Development Agreement and the right to acquire its pro rata share of additional properties acquired by Wapiti within the area of mutual interest identified in the Development Agreement. We have not incurred any costs to date and there is substantial doubt regarding our ability to fund our share of the drilling and completion costs.
The drilling and completion program will continue until Wapiti’s funding commitment has been fully expended or for a shorter period, if the Operating Committee (as defined below) votes to cease the drilling program after Wapiti has expended $10.0 million on drilling and completion costs related to the program wells (the “Drilling Term”).
With respect to wells drilled pursuant to the drilling program, the net revenue interest attributable to such wells from the closing through the time when the cumulative proceeds received by Wapiti from such wells equals the amount of costs actually paid by Wapiti in respect of such wells and the drilling program (such time, “Payout”), will be allocated 32.5% to us and 67.5% to Wapiti. After Payout, the net revenue interest will be allocated in proportion to the actual net revenue interests of the parties in such wells. With respect to each well drilled pursuant to the drilling program, (i) all drilling and completion costs will be borne (a) during the Drilling Term, 20% by us and 80% by Wapiti, (b) after the Drilling Term but before Payout, 32.5% by us and 67.5% by Wapiti, and (c) after Payout, in proportion to the actual working interests of the parties in such wells, and (ii) all other working interest costs will be borne (x) before Payout, 32.5% by us and 67.5% by Wapiti, and (y) after Payout, in proportion to the actual working interests of the parties in such wells.
Subject to the terms of the Development Agreement, we will manage the operations contemplated by the drilling program. Except for the subject assets that are already subject to joint operating agreements with third parties, the operation of (i) a portion of the subject assets will be subject to an agreed upon joint operating agreement (a “JOA”), which names Gasco Production Company as operator of record, and (ii)
the remaining portion of the subject assets will be subject to an agreed upon JOA, which names Wapiti as operator of record. Gasco Production Company and Wapiti also entered into a contract operating agreement naming Gasco Production Company as contract operator with respect to the portion of the subject assets for which Wapiti is named as operator of record. However, to the extent that Gasco Production Company, as operator under these agreements, becomes insolvent, bankrupt or is placed into receivership, it will be deemed to have resigned as operator or the other party may have termination rights. Wapiti and we have formed an Operating Committee (the “Operating Committee”) to oversee generally the drilling program and operations in the project area and to approve certain matters specified in the Development Agreement. The Operating Committee consists of two members from each of us and Wapiti, with the members appointed by each party having an aggregate 50% vote.
The Development Agreement contains transfer restrictions on each of our and Wapiti’s ability to transfer its respective interests in the subject assets. The Development Agreement also contains a customary area of mutual interest provision covering the Project Area. With certain limited exceptions, the Development Agreement will remain in effect during the Drilling Term; however, after the six-month anniversary of the end of the Drilling Term, the Development Agreement may be terminated by either us or Wapiti upon six months’ advance notice.
Due to low natural gas prices and permitting delays, we did not drill any natural gas wells in Utah from the closing of the Uinta Basin Transaction through the remainder of 2012.
NYSE MKT LLC Communications
On December 6, 2012, we received a notice from the Exchange indicating that we do not satisfy the continued listing standards of the Exchange set forth in Section 1003(f)(v) of the NYSE MKT LLC Company Guide (the “Company Guide”) because our common stock has traded at a low price per share for a substantial period of time. We have not yet determined what action, if any, we will take in response to this notice. In the notice, the Exchange predicates our continued listing on the Exchange on us effecting a reverse stock split of our common stock by June 6, 2013.
On January 11, 2013, we received a notice from the Exchange indicating that we do not satisfy the continued listing standards of the Exchange set forth in Section 1003(a)(iv) of the Company Guide, which applies if a listed company has sustained losses which are so substantial in relation to its overall operations or its existing financial resources, or its financial condition has become so impaired that it appears questionable, in the opinion of the Exchange, as to whether such company will be able to continue operations and/or meet its obligations as they mature.
In order to maintain our listing, we were required to submit a plan of compliance (a “Plan”) addressing how we intend to regain compliance with Section 1003(a)(iv) of the Company Guide by June 30, 2013. We provided the Exchange with a Plan on February 11, 2013, that addressed how we intend to regain to compliance with Section 1003(a)(iv) of the Company Guide. Pursuant to the Plan, we intend to lower costs, rationalize assets, refocus our development program toward oil and liquids, especially in the Green River Formation, and continue our California program with the potential goal of expanding our California model. The Plan also considers strategic alternatives, including the debt restructuring and sales of assets, if necessary. However, there can be no assurance that the Plan will be accepted by the Exchange or that we will be able to achieve compliance with the Exchange’s continued listing standards within the required time frame. If the Plan is not accepted, we will be subject to delisting proceedings.
Furthermore, if the Plan is accepted but we are not in compliance with the continued listing standards of the Company Guide by June 30, 2013, or if we do not make progress consistent with the Plan, the Exchange staff will initiate delisting proceedings as it deems appropriate.
Environmental Impact Statement
In June 2012, the U.S. Bureau of Land Management (“BLM”) signed the Record of Decision (“ROD”) on the Environmental Impact Statement that authorizes the development of our Uinta Basin field in Duchesne and Uintah Counties, Utah. This field includes our core Riverbend Project. However on January 18, 2013, certain non-governmental environmental organizations, including the Southern Utah Wilderness Alliance (“SUWA”), filed a suit against the BLM challenging the ROD and alleging that the BLM failed to comply with the requirements of the National Environmental Policy Act, as amended (“NEPA”), and its implementing regulations. On February 13, 2013, SUWA voluntarily submitted notice of dismissal of the suit to the District Court. For more information, see “Item 3 - Legal Proceedings - NEPA Suit.”
Our project will tap an existing gas field that already has 133 producing wells and extensive infrastructure, pipelines and roads. We will also continue to explore for oil and gas in other parts of the project area. The project area is located primarily on 177,644 gross acres of BLM-administered lands.
Green River Oil Wells
In December 2011, we began drilling two wells to the Green River Formation, both in which we currently own a 50% working interest. These wells were successfully completed during January 2012. The wells are on pump and continue to produce oil as expected.
During the third quarter 2012, we implemented a workover program to target by-passed oil in older Wasatch / Mesaverde oil wells and Green River oil wells. Since the workover program commenced in the second half of 2012, we have performed eight workovers in the Green River Formation which have yielded a per-well average of a 15% to 20% increase in net oil production, as compared to rates recorded prior to the well workovers.
We believe that the workover program presents a low-cost opportunity to boost oil production in advance of the new-drill Green River oil program that is expected to commence during the third quarter of 2013, depending on rig availability. We continue to identify wells suitable for by-passed oil workovers, and have identified an additional three wells for workover activities and further production enhancement.
Drilling Plans
Our six-well Green River oil well program is now fully permitted. However, the newly issued permits include burrowing owl and golden eagle drilling stipulations that will delay the spudding of these six wells until the third quarter of 2013. Five additional Green River oil well locations are in the process of being permitted by regulatory agencies and we anticipate that these permits will be issued before the third quarter of 2013 and added to the drilling schedule along with the six-well Green River oil well program. We are also in the process of permitting our Uinta Basin natural gas pad-well drilling program.
We have a participating interest in a horizontal well (7.14% working interest/non-operated) to test the productive potential of the oil-prone C-Shoal member of the Green River Formation. The well, with a proposed 4,250 foot lateral length, will be operated by an industry partner that has successfully drilled numerous horizontal Green River oil wells in the Uinta Basin. The operator spud the well in February 2013.
As described previously, there is substantial doubt regarding our ability to generate sufficient cash flows from operations to fund our ongoing operations, and we currently anticipate that cash on hand and
forecasted cash flows from operations will only be sufficient to fund cash requirements for working capital, including debt payment obligations, through the second quarter of 2013. These factors raise substantial doubt about our ability to continue as a going concern. Our drilling plans will be adjusted or completely terminated if we do not have adequate cash flow to fund these projects. For example, we have not allocated any amounts to the 2012 capital budget.
Working Interest Acquisition
During December 2012, we acquired additional working interests in 32 producing wells in the Riverbend area of Utah, in which we have a working interest and operate, for $177,620. The acquired interests range from 4% to 10% per well with an average of 8% per well and represented an estimated increase to our reserves of approximately 596,000 Mcfe.
California Projects
Willow Springs
The exploratory well drilled in this area tested non-commercial rates of oil in the Phacoides Formation and our partner moved up the well bore to test additional potential pay horizons. Two tests were made of the Monterey Shale in an off-structure position. While both zones indicated decent quality reservoir characteristics, both zones encountered non-commercial rates of hydrocarbons. Based upon all of the testing results, our partner made the decision to plug and abandon the well. While the Willow Springs well did not find commercial hydrocarbons, it did confirm our structural geologic model by finding oil within the Phacoides Formation and confirmed the existence of the Monterey Shale reservoir.
Our partner has the option of spudding a second well within the Willow Springs acreage before March 13, 2013.
Antelope Valley
In order to complete the processing of the large Antelope Valley 3D seismic survey, our partner was granted a one-year extension in the spudding of the first test earning well at our Antelope Valley prospects. The first test well is expected to be spud before July 2013. In exchange for the drilling extension, our partner has agreed to pay for all lease rentals between July 1, 2012 and the spudding of the first exploratory well. Our partner has also committed to spudding a well on the Southwest Cymric prospect prior to December 31, 2013.
Northwest McKittrick
The operator of the Northwest McKittrick prospect recently reached total depth on the first of three earning wells on which we are carried for a 20% working interest. Well logs identified the presence of a structure which helps confirm our geologic model; however, the well penetrated the primary objective 300 feet down-dip from the targeted depth.
As part of the terms of the farm-out agreement, the partner in Northwest McKittrick has until March 12, 2013 to spud the second test well to continue to fully earn into the prospect. Our partner has notified us that they don’t intend to drill a second well. We are currently seeking a replacement partner for this project.
Southwest Cymric
During January 2012, we entered into an arrangement with an exploration and production company which operates in California, pursuant to which we received a $750,000 prospect fee related to certain of our California acreage. The fee reimbursed costs that we have invested in the area and provides us with a potential carried interest of 20% in one well to be drilled on the acreage. Our arrangement with the
operator requires them to spud this well prior to January 18, 2014 in order to earn their share of the prospect.
Gas Processing Agreements
On March 22, 2012, we entered into an Amended and Restated Gas Gathering and Processing Agreement (the “Amended and Restated Monarch Agreement”) with Monarch Natural Gas, LLC, a Delaware limited liability company (“Monarch”), which amends, restates and replaces the Gas Gathering and Processing Agreement effective March 1, 2010 (the “Existing Monarch Agreement”). Pursuant to the terms of the Existing Monarch Agreement, we dedicated the gas production from all of our Utah acreage to Monarch and Monarch agreed to provide gathering, compression and processing services to us.
Under the Amended and Restated Monarch Agreement, Monarch agreed, among other things, to (a) release and waive its rights to process the first 50,000 MMBtu/day of our gas delivered to Monarch’s gathering system pursuant to the Amended and Restated Monarch Agreement (the “Excluded Production”) and (b) retain all processing rights for all gas volumes produced from certain of our reserves in excess of the Excluded Production. The Excluded Production may be reduced if we fail to meet certain drilling investment targets. The Amended and Restated Monarch Agreement also provides that we are committed to deliver to Monarch for gathering a minimum of 25,000 Mcf/day and we are obligated to pay for any shortfall following the end each quarterly period, measured by the shortfall quantity for the quarter multiplied by the then-current gathering and processing fees under the agreement.
In connection with the Amended and Restated Monarch Agreement, we also entered in to the QPC Transportation Agreement pursuant to which we agreed to enter into separate transportation services agreements for firm transportation services. We are currently committed to deliver to QPC for transportation services a minimum of 25,000 MMBtu/day.
During the year ended December 31, 2012, the Amended and Restated Monarch Agreement covered the gathering, processing, compressing and delivery of our gross production of natural gas from all of our Utah acreage from wellheads to points of sale.
Effective February 7, 2013, Chipeta Processing LLC (“Chipeta”) began processing the natural gas production from our Utah acreage through a cryogenic processing facility that was built by Chipeta. Pursuant to the Chipeta Processing Agreement, which we signed on September 21, 2011 and subsequently amended on December 1, 2012, we reserved 25,000 Mcf/d of capacity in the Chipeta processing plant for cryogenic processing and agreed to pay specified processing fees per MMBtu as well as a pro rata share of all applicable electric compression costs, subject to escalation on an annual basis. The primary term of the Chipeta Processing Agreement began upon the completion of the building of Chipeta’s facility on February 7, 2013. Under this agreement, we are committed to deliver, on average, at least 90% of our contracted cryogenic capacity of 25,000 Mcf/d (the “Minimum Daily Quantity”) during each monthly accounting period. Following the first twelve monthly accounting periods, Chipeta may determine whether we failed to deliver equal to or greater than the Minimum Daily Quantity multiplied by the number of days in the annual accounting period. If we delivered less than the quantity we committed to deliver, we would be required to pay a deficiency payment equal to the contracted cryogenic processing fee multiplied by the deficient quantity. In addition, to the extent that Chipeta has reasonable grounds for uncertainty regarding the performance of our obligations under our gas processing agreement, including a material change in our creditworthiness, Chipeta may sell our natural gas and apply amounts received against any amounts we owe to Chipeta, set off any amount owed to us against amounts owed to Chipeta or cease processing our natural gas until our account is current, with interest. Chipeta may also demand adequate assurance of performance from us, which may be in the form of a standby irrevocable letter of credit, prepayment or performance bond or guaranty.
Since the beginning of the primary term of the Chipeta Processing Agreement, Chipeta has provided all of our natural gas processing services, and we have not produced any amounts of natural gas in excess of the Excluded Production. Monarch and QPC continue to gather and transport our natural gas. Please read “Item 1A
ITEM 1A. Risk Factors
Described below are known material risks that we believe are applicable to our business and the oil and natural gas industry in which we operate. There may be additional risks that are not presently material or known to us. You should carefully consider each of the following material risks and all other information set forth in this Annual Report.
If any of the events described below occur, our business, financial condition, results of operations, liquidity or access to the capital markets could be materially adversely affected and you could lose part or all of your investment in our securities.
Risks Related to Our Liquidity and Indebtedness
We currently anticipate that our cash on hand as well as forecasted cash flows from operations will only be sufficient to fund our anticipated cash requirements for working capital purposes and normal capital expenditures through the second quarter of 2013. If we are unable to generate sufficient cash flows, secure additional capital or otherwise restructure or refinance our business, we would not be able to continue as a going concern, and could potentially be forced to seek relief through a filing under Chapter 11 of the U.S. Bankruptcy Code (or an involuntary petition for bankruptcy may be filed against us).
Our consolidated financial statements included in this Annual Report on Form 10-K (“Annual Report”) have been prepared assuming that we will continue as a going concern, which contemplates realization of assets and the satisfaction of liabilities in the normal course of business for the next twelve months. However, due to the significant extended decline in the natural gas market and sustained low natural gas prices caused by excess production and stagnant growth in the demand for natural gas, we have not been able to recover our exploration and development costs as anticipated. For example, we had net losses and negative cash flow from operations for the three and twelve months ended December 31, 2012 and at December 31, 2012 had an accumulated deficit of $244,808,156. There is substantial doubt regarding our ability to generate sufficient cash flows from operations to fund our ongoing operations, and we currently anticipate that cash on hand and forecasted cash flows from operations will only be sufficient to fund cash requirements for working capital, including debt payment obligations, through the second quarter of 2013. This expectation is based on various assumptions, including those related to future natural gas and oil prices, production results and the effectiveness of our cash management strategy discussed below, some or all of which may not prove to be correct and may result in our inability to meet cash requirements prior to the second quarter of 2013. Our prior revolving credit facility matured in June 2012, at which time we repaid all of the outstanding borrowings thereunder. While we have attempted to secure a replacement facility, as of the date of this Annual Report, we have been unable to do so on acceptable terms and are no longer actively in discussions to obtain a replacement facility. Furthermore, we may not achieve
profitability from operations in the near future or at all and we may continue to experience significant losses. These factors raise substantial doubt about our ability to continue as a going concern.
As of December 31, 2012, we had $45,168,000 aggregate principal amount of our 5.5% Convertible Senior Notes due 2015 (the “2015 Notes”) outstanding. The 2015 Notes bear interest at a rate of 5.50% per annum, payable in cash semi-annually in arrears on April 5th and October 5th of each year. Our failure to make an interest payment on the 2015 Notes, if not cured within 30 days, or the delisting of our common stock from the Exchange would result in a default under the indenture governing the 2015 Notes, which would permit the holders of the 2015 Notes to accelerate repayment of the 2015 Notes.
Failure to generate operating cash flow or to obtain additional financing for the development of our properties could result in substantial dilution of our property interests or delay or cause indefinite postponement of further exploration and development of our prospects resulting in the possible loss of our properties. This could cause us to alter our business plans, including further reducing our exploration and development plans. In particular, we face uncertainties relating to our ability to fund the level of capital expenditures required for oil and gas exploration and production activities. We intend to fund our anticipated cash requirements through the second quarter of 2013 primarily through cash on hand and cash flows from operations, although we cannot assure you that cash on hand and cash flows from operations will be sufficient to fund such requirements. If they are not, our liquidity and results of operations will be materially adversely affected and we would not be able to continue as a going concern.
To continue as a going concern, we must generate sufficient operating cash flows, secure additional capital or otherwise pursue a strategic restructuring, refinancing or other transaction to provide us with additional liquidity. The urgency of our liquidity constraints may require us to pursue such a transaction at an inopportune time. Moreover, our ability to successfully implement, and the cost of, any such transaction will depend on numerous factors, including:
· demand and prices for natural gas and oil;
· general economic conditions;
· strength of the credit and capital markets;
· our ability to successfully execute our operational strategies, and our operating and financial performance;
· our ability to remain in compliance with our debt and equity instruments;
· our ability to remain in compliance with our operational agreements, including our gas processing, gathering and transportation agreements;
· our counterparties refraining from exercising any remedies available as a result of the determination that we are insolvent or unable to perform in accordance with the contract;
· our stock price, and ability to regain and maintain compliance with the Exchange’s continued listing requirements;
· our ability to maintain relationships with our suppliers, customers, employees, stockholders and other third parties; and
· market uncertainty in connection with our ability to continue as a going concern as well as investor confidence in us.
If we fail to generate sufficient operating cash flows, secure additional capital or otherwise restructure or refinance our business before the end of the second quarter of 2013, we will not have adequate liquidity to fund our operations and meet our obligations (including our debt payment obligations), we will not be able to continue as a going concern, and could potentially be forced to seek relief through a filing under Chapter 11 of the U.S. Bankruptcy Code (or an involuntary petition for bankruptcy may be filed against us). If we file for bankruptcy protection, our business and operations will be subject to certain risks.
A bankruptcy filing by or against us would subject our business and operations to various risks, including but not limited to, the following:
· a bankruptcy filing by or against us may adversely affect our business prospects, including our ability to continue to obtain and maintain the contracts necessary to operate our business on competitive terms;
· a bankruptcy filing by or against us may cause an event of default under the indenture governing the 2015 Notes;
· certain provisions in our operating agreements may be triggered such that we would be deemed to have resigned as operator or the agreements may be terminated by the other party;
· we may be unable to retain and motivate key executives and employees through the process of reorganization, and we may have difficulty attracting new employees;
· there can be no assurance as to our ability to maintain or obtain sufficient financing sources for operations or to fund any reorganization plan and meet future obligations;
· there can be no assurance that we will be able to successfully develop, prosecute, confirm and consummate one or more plans of reorganization that are acceptable to the bankruptcy court and our creditors, equity holders and other parties in interest; and
· the value of our common stock could be reduced to zero as result of a bankruptcy filing.
We also cannot assure you that our common stock will be liquid or that it will remain listed on the Exchange as described in greater detail below.
In order to address our liquidity constraints and in addition to our ongoing efforts to secure additional capital or otherwise pursue a strategic restructuring, refinancing or other transaction to provide us with additional liquidity, we have embarked on a cash management strategy to enhance and preserve as much liquidity as possible. This plan contemplates us, among other things:
· reducing expenditures by eliminating, delaying or curtailing discretionary and non-essential spending, and not designating any capital budget for 2013;
· managing working capital;
· delaying certain drilling projects;
· pursuing farm-out and other similar types of transactions to fund working capital needs;
· evaluating our options for the divestiture of certain assets;
· considering asset purchases through the issuance of equity;
· investigating merger opportunities; and
· restructuring and reengineering our organization and processes to reduce operating costs and increase efficiency.
We cannot provide any assurances that we will be successful in accomplishing any of these plans or that any of these actions can be effected on a timely basis, on satisfactory terms or maintained once initiated. Furthermore, our cash management strategy, if successful, may limit certain of our operational and strategic initiatives designed to grow our business over the long term.
Our stock price has been volatile and any investment in our common stock could suffer a significant decline or total loss in value. Furthermore, we are not currently in compliance with and cannot assure you that we will be able to regain and maintain compliance with the continued listing standards of the Exchange.
Because we face significant uncertainties relating to our ability to generate sufficient cash flows from operations and to continue to operate our business, our stock price is volatile and any investment in our
common stock could suffer a significant decline in value. Furthermore, we may not be able to regain or maintain compliance with the continued listing standards of the Exchange. The Exchange requires companies to meet certain continued listing criteria as outlined in the Company Guide. We are currently not in compliance with such criteria. We have received formal notices from the Exchange regarding noncompliance with the Exchange’s continued listing criteria.
On December 6, 2012, we received a notice indicating that we do not satisfy the continued listing standards set forth in Section 1003(f)(v) of the Company Guide because our common stock has traded at a low price per share for a substantial period of time. We have not yet determined what action, if any, we will take in response to this notice. In the notice, the Exchange predicates our continued listing on the Exchange on us effecting a reverse stock split of our common stock by June 6, 2013.
On January 11, 2013, we received a notice from the Exchange indicating that we do not satisfy the continued listing standards set forth in Section 1003(a)(iv) of the Company Guide, which applies if a listed company has sustained losses which are so substantial in relation to its overall operations or its existing financial resources, or its financial condition has become so impaired that it appears questionable, in the opinion of the Exchange, as to whether such company will be able to continue operations and/or meet its obligations as they mature.
We provided the Exchange with a Plan on February 11, 2013, to address how we intend to regain to compliance with Section 1003(a)(iv) of the Company Guide. Pursuant to the Plan, we intend to lower costs, rationalize assets, refocus our development program toward oil and liquids, especially in the Green River Formation, and continue our California program with the potential goal of expanding our California model. The Plan also considers strategic alternatives, including the debt restructuring and sales of assets, if necessary. However, there can be no assurance that the Plan will be accepted by the Exchange or that we will be able to achieve compliance with the Exchange’s continued listing standards within the required time frame. If the Plan is not accepted, we will be subject to delisting proceedings.
Furthermore, if we are not in compliance with the continued listing standards of the Company Guide by June 30, 2013, or if we do not make progress consistent with the Plan, the Exchange staff will initiate delisting proceedings as it deems appropriate.
The delisting of our stock from the Exchange could result in even further reductions in our stock price, would substantially limit the liquidity of our common stock, and materially adversely affect our ability to raise capital or pursue strategic restructuring, refinancing or other transactions on acceptable terms, or at all. Delisting from the Exchange could also have other negative results, including the potential loss of confidence by suppliers and employees, the loss of institutional investor interest and fewer business development opportunities. Furthermore, delisting may result in an event of default under the indenture governing our 2015 Notes, which requires that we list the shares of common stock that may be issued upon conversion of the 2015 Notes and the Preferred Stock on the Exchange or any other U.S. national or regional securities exchange.
Pursuant to the Gas Processing Agreement with Chipeta and the Amended and Restated Monarch Agreement, we may be required to make periodic deficiency payments for any shortfalls from the specified minimum volume commitments.
Pursuant to our Gas Processing Agreement with Chipeta, we dedicated certain of our natural gas production from our acreage in Utah to Chipeta for processing. We reserved 25,000 Mcf/d of capacity in the Chipeta processing plant for cryogenic processing and agreed to pay specified processing fees per MMBtu as well as a pro rata share of all applicable electric compression costs, subject to escalation on an annual basis. The primary term of the Chipeta Processing Agreement began upon the completion of the building of Chipeta’s facility on February 7, 2013. Under this agreement, we are committed to deliver, on
average, at least 90% of our contracted cryogenic capacity of 25,000 Mcf/d during each monthly accounting period, which is referred to as the Minimum Daily Quantity. Following the first twelve monthly accounting periods, Chipeta may determine whether we failed to deliver equal to or greater than the Minimum Daily Quantity multiplied by the number of days in the annual accounting period. If we delivered less than the quantity we committed to deliver, we would be required to pay a deficiency payment equal to the contracted cryogenic processing fee multiplied by the deficient quantity.
Pursuant to the Amended and Restated Monarch Agreement, Monarch agreed, among other things, to release and waive its existing right to process the “Excluded Production” and retain all processing rights for all gas volumes produced from certain of our reserves in excess of the Excluded Production. The Excluded Production may be reduced if we fail to meet certain drilling investment targets after three years from the beginning of primary term of the Chipeta Processing Agreement, which was February 7, 2013. The Amended and Restated Monarch Agreement also provides that we are committed to deliver to Monarch for gathering a minimum of 25,000 Mcf/day and we are obligated to pay for any shortfall following the end each quarterly period, measured by the shortfall quantity for the quarter multiplied by the then-current gathering and processing fees under the agreement.
Pursuant to the QPC Transportation Agreement, we are also committed to deliver to QPC 25,000 MMBtu/day for firm transportation services.
There is substantial doubt regarding our ability to generate sufficient cash flows from operations to fund our ongoing operations. The maximum undiscounted deficiency payments under the Chipeta Processing Agreement, the Amended and Restated Monarch Agreement and the QPC Transportation Agreement, over the full terms of these contracts, are estimated to be approximately $59 million. Of this amount, approximately $40 million would be owed to Chipeta, $8.5 million would be owed to Monarch and $12.5 million would be owed to QPC. These amounts are owed regardless of whether we deliver any natural gas quantities to the applicable parties. If we are unable to fund additional drilling projects, and based on our December 31, 2012 reserve estimates, assuming no future drilling and constant gas prices, we estimate that we could have a reasonably possible minimum production shortfall of approximately 54,000 MMcf valued at approximately $37 million in aggregate deficiency payment obligations on an undiscounted gross basis.
We are considering several alternatives to mitigate the reasonably possible estimated production shortfall such as the sale of our firm commitment positions, seeking relief from the firm commitments because of the permitting delays in the area and the purchase of production quantities to meet our minimum production requirements. Also, future increases in gas prices would increase the related reserve estimates and reduce possible shortfalls. However, there is no assurance we will be successful in accomplishing these actions should there be a deficiency. Accordingly, we have not accrued any amounts as of December 31, 2012 as it is not probable or reasonably estimable. Please read “Item 1 - Business-2012 and Recent Highlights-Gas Processing Agreements” and “Item 2.-Properties-Delivery Commitments” for more information.
We have incurred losses and may continue to incur losses in the future. In addition, we have a significant accumulated deficit as of December 31, 2012.
During the years ended December 31, 2012 and 2011, we incurred net losses of $22,232,391 and $7,301,645, respectively. Furthermore, as of December 31, 2012, we had an accumulated deficit of $244,493,156. During these periods, our cash flows were insufficient to provide working capital for our ongoing overhead, the funding of our lease acquisitions and the exploration and development of our properties. Because we may face similar shortfalls in the future, and in light of the volatile nature of commodity prices and other uncertainties described in this “Item 1A.- Risk Factors” and elsewhere in this Annual Report, we may be unable to successfully develop any prospects that we have or acquire any
additional properties without adequate financing and we may not achieve profitability from operations in the near future or at all. Our failure to achieve profitability in the future could materially adversely affect the trading price of our common stock as well as our ability to raise additional capital to fund our operations.
Lack of access to the credit market could negatively impact our ability to operate our business and to execute our business strategy.
Due to the changes in the global credit market in the recent past, there has been deterioration in the credit and capital markets and access to financing is limited and uncertain. If the capital and credit markets continue to experience weakness and the availability of funds remains limited, we may incur increased costs associated with any additional financing we may require for future operations or we may be unable to obtain such financing at all. For example, we have been unable to secure adequate alternative financing to replace our revolving credit facility which expired in June 2012. Our suppliers may also be unable to sustain their current level of operations, fulfill their commitments and/or fund future operations and obligations, each of which could adversely affect our operations.
In addition, some financial institutions and insurance companies have reported significant deterioration in their financial condition. Our forward-looking statements assume that our insurers and other institutions with whom we do business will be able to fulfill their obligations under the various insurance policies or other contracts that we may have with such parties. If these third parties were unable to perform under such agreements, and if we were unable to find suitable replacements at a reasonable cost, our results of operations, liquidity and cash flows could be adversely impacted.
The indenture governing our 2015 Notes imposes restrictions on us that may affect our ability to successfully operate our business.
The indenture governing our 2015 Notes imposes certain operational and financial restrictions on us that limit our ability to:
· incur additional indebtedness;
· create liens;
· sell our assets to, or consolidate or merge with or into, other companies;
· make investments and other restricted payments, including dividends; and
· engage in transactions with affiliates.
Generally, the restrictions under our indenture could limit our ability to obtain future financings, make needed capital expenditures, withstand a downturn in our business or the economy in general, or otherwise conduct necessary corporate activities.
Our failure to comply with any material provision or covenant of our indenture, including, among other things, failure to pay any installment of interest or principal on the 2015 Notes, failure to issue shares of common stock upon conversion of the 2015 Notes when required to be delivered, delisting of our common stock from the Exchange, commencement by us of a voluntary bankruptcy proceeding, or entry of a bankruptcy order or decree against us, could result in a default which would, absent a waiver or amendment, require immediate repayment of the 2015 Notes and potentially trigger certain provisions in our operating agreements. For example, under the JOA and contract operating agreements in connection
with the Uinta Basin Transaction pursuant to which we serve as operator, if we become insolvent or bankrupt or are placed into receivership, we will be deemed to have resigned as operator or the other party may have termination rights. If this were to occur, we cannot assure you that our assets would be sufficient to repay in full the money owed to our debt holders. In addition, to the extent it was necessary to address any anticipated covenant compliance issues prior to default, we may be required to sell a portion of our assets or issue additional securities, which would be dilutive to our existing shareholders. Given the condition of current credit and capital markets and our current liquidity position, any sale of assets or issuance of additional securities may not be available on terms acceptable to us or at all.
Risks Related to Our Business and Industry
Lower oil and natural gas prices and other factors, including downward revisions of the present value of our proved reserves and increased drilling expenditures without current additions to proved reserves, have resulted, and in the future may result, in ceiling test write-downs and other impairments of our asset carrying values. We are subject to the full cost ceiling limitation which has resulted in past write-downs of estimated net reserves and may result in a write-down in the future if commodity prices continue to decline.
We may be required to write down the carrying value of our gas and oil properties when gas and oil prices are low or if there are substantial downward adjustments to our estimated proved reserves, increases in the estimates of development costs or deterioration in exploration results. Because we have elected to use the full cost accounting method, we are subject to quarterly calculations of a “ceiling” or limitation on the amount of our oil and gas properties that can be capitalized on our balance sheet. As explained below, the discounted present value of our proved reserves is a major component of the ceiling calculation and the risk that we will be required to write down the carrying value of oil and natural gas properties increases when natural gas and oil prices are depressed or volatile. Significant price declines could cause us to take one or more ceiling test write-downs, which would be reflected as non-cash charges against current earnings.
Under the full cost method of accounting, capitalized gas and oil property costs less accumulated depletion and net of deferred income taxes may not exceed an amount equal to the present value, discounted at 10%, of estimated future net revenues from proved gas and oil reserves less the future cash outflows associated with the asset retirement obligations that have been accrued on the balance sheet plus the cost, or estimated fair value, if lower, of unproved properties and the costs of any property not being amortized.
If the net capitalized costs of our oil and gas properties exceed the cost ceiling, we are subject to a ceiling test write-down of our estimated net reserves to the extent of such excess. The present value of estimated future net revenues is computed by applying the twelve month trailing average first-of-month prices of gas and oil to estimated future production of proved gas and oil reserves as of period-end, less estimated future expenditures to be incurred in developing and producing the proved reserves assuming the continuation of existing economic conditions. Expense recorded in one period may not be reversed in a subsequent period even though higher natural gas and crude oil prices may have increased the ceiling applicable in the subsequent period.
As of March 31, 2012, June 30, 2012, September 30, 2012 and December 31, 2012, the full cost pool exceeded the ceiling limitation based on the average first-day-of-the-month oil and gas prices of $82.58 per barrel and $2.94 per Mcf during the 12-month period ended March 31, 2012, $81.16 per barrel and $2.57 per Mcf during the 12-month period ended June 30, 2012, $80.35 per barrel and $2.23 per Mcf during the 12-month period ended September 30, 2012, and $80.25 per barrel and $2.15 per Mcf of gas
during the 12-month period ended December 31, 2012. Therefore, impairment expense of $16,486,000 was recorded during the year ended December 31, 2012.
Our evaluation of impairment of unproved properties incorporates our expectations of developing unproved properties given current and forward-looking economic conditions and commodity prices. Investments in unproved properties with a carrying value of approximately $31,486,314 as of December 31, 2012, including capitalized interest costs, are assessed periodically to ascertain whether impairment has occurred. Impairments in such properties may result from lower commodity prices, expiration of leases, inability to find partners, inadequate financing or unsuccessful drilling results. Unproved properties whose costs are individually significant are assessed individually by considering the primary lease terms of the properties, the holding period of the properties, and geographic and geologic data obtained relating to the properties. The amount of impairment assessed, if any, is added to the costs to be amortized, or is reported as a period expense, as appropriate. If an impairment of unproved properties results in a reclassification to proved oil and gas properties, the ceiling test cushion would be reduced.
We believe that the majority of our remaining unproved costs will become subject to depletion within the next five years, by proving up reserves relating to the acreage through exploration and development activities, by impairing the acreage that will expire before we can explore or develop it further, or by making decisions that further exploration and development activity will not occur.
During the year ended December 31, 2012, we reclassified approximately $7,942,000 of acreage costs in Utah and California into proved property. This reclassification is comprised of a $7,000,000 decrease in the carrying value of our Utah acreage based upon an independent appraisal as of December 31, 2012 and $942,000 representing the value of leases that expired during 2012. During 2011, we reclassified $660,000 of acreage costs in Nevada into proved property as we relinquished our control over this acreage to another party in exchange for a small overriding royalty interest on any future drilling projects.
Lower oil and natural gas prices have historically and may continue to negatively impact our ability to produce economically.
Lower natural gas and oil prices have resulted in significant decreases in our revenue, and have adversely affected the amount of oil and natural gas that we can produce economically. A reduction in production has resulted in a shortfall in our expected cash flows and caused us to significantly reduce our capital spending. Additional financing may not be available on acceptable terms or at all. This reduction has also resulted in our having to make substantial downward adjustments to our estimated proved reserves. The price per barrel of oil reflects our blend of oil and condensate. If the prices for oil and gas decrease materially from year end 2012 prices, we will be unable to economically develop most of our acreage. Any of these factors could negatively impact our ability to replace our production and our ability to continue as a going concern.
Oil and natural gas prices are volatile. The extended decline in commodity prices has adversely affected, and in the future will continue to adversely affect, our financial condition and results of operations, cash flows, access to the capital markets, and ability to grow.
Our financial condition, operating results, and future rate of growth depend primarily upon the prices that we receive for our oil and natural gas. Prices also affect our cash flow available for capital expenditures and are likely to affect our ability to access the credit and capital markets. Natural gas and oil prices are set by broad market forces, which historically have been and are likely to remain volatile in the future. Prices for natural gas and oil are subject to wide fluctuations in response to relatively minor changes in the supply of and demand for natural gas or oil, market uncertainty and a variety of additional factors that are beyond our control, such as:
· changes in the global supply and demand for natural gas and oil;
· commodity processing, gathering and transportation availability;
· domestic and global political and economic conditions;
· the ability of members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;
· weather conditions, including hurricanes;
· technological advances affecting energy consumption;
· an increase in alternative fuel sources;
· higher fuel taxes and other regulatory actions;
· an increase in fuel economy;
· additional domestic and foreign governmental regulations; and
· the price and availability of alternative fuels.
Our success is influenced by natural gas prices in the specific area where we operate, and these prices may be lower than prices at major markets.
Regional natural gas prices may move independent of broad industry price trends. Because some of our operations are located outside major markets, we are directly impacted by regional natural gas prices regardless of major market pricing. All of our natural gas production is currently located in, and all of our future natural gas production is anticipated to be located in, the Rocky Mountain Region of the United States. The gas prices that we and other operators in the Rocky Mountain region have received and are receiving are at a discount to gas prices in other parts of the country.
Additional factors that can cause price volatility for crude oil and natural gas within this region are:
· the availability of gathering systems with sufficient capacity to handle local production;
· seasonal fluctuations in local demand for production;
· local and national gas storage capacity;
· interstate pipeline capacity; and
· the availability and cost of gas transportation facilities from the Rocky Mountain region.
It is impossible to predict natural gas and oil price movements with certainty. A substantial or extended decline in natural gas and oil prices would materially and adversely affect our future business, financial condition, results of operations, liquidity and ability to finance capital expenditures.
The enactment of derivatives legislation and regulation by the United States Congress could have an adverse effect on our ability to use derivative instruments to reduce the negative effect of commodity price changes, interest rate fluctuations and other risks associated with our business.
To mitigate the impact of lower commodity prices on our cash flows, we sometimes enter into commodity derivative instruments, however we do not currently have any derivative instruments. See Note 6 - Derivatives of the accompanying consolidated financial statements for further discussion.
On July 21, 2010 new comprehensive financial reform legislation, known as the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Act”), was enacted that establishes federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market. The Act requires the CFTC, the SEC and other regulators to promulgate rules and regulations implementing the new legislation. In its rulemaking under the Act the CFTC has issued final regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. Certain bona fide hedging transactions would be exempt from these position limits. The position limits rule was vacated by the United States District Court for the District of Colombia in September of 2012 although the CFTC has stated that it will appeal the District Court’s decision. The CFTC also has finalized other regulations, including critical rulemakings on the definition of “swap”, “security-based swap”, “swap dealer” and “major swap participant”. The Act and CFTC Rules also will require us in connection with certain derivatives activities to comply with clearing and trade-execution requirements (or take steps to qualify for an exemption to such requirements). In addition new regulations may require us to comply with margin requirements although these regulations are not finalized and their application to us is uncertain at this time. Other regulations also remain to be finalized, and the CFTC recently has delayed the compliance dates for various regulations already finalized. As a result it is not possible at this time to predict with certainty the full effects of the Act and CFTC rules on us and the timing of such effects. The Act may also require the counterparties to any future derivative instruments to spin off some of their derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty. The Act and any new regulations could significantly increase the cost of derivative contracts (including from swap recordkeeping and reporting requirements and through requirements to post collateral which could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks that we encounter, and increase our exposure to less creditworthy counterparties. Finally, the Act was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of Act is to lower commodity prices. Any of these consequences could have a material, adverse effect on us, our financial condition, and our results of operations.
We have entered into a significant joint venture. This joint venture restricts our operational and corporate flexibility; actions taken by our joint venture partner may materially impact our financial position and results of operation; and we may not realize the benefits we expect to realize from this joint venture.
On March 22, 2012, we closed the Uinta Basin Transaction with Wapiti, and in connection with such closing, we (i) sold to Wapiti an undivided 50% of our interest in certain of our Uinta Basin producing oil and gas assets for $18.0 million in cash and $1.19 million in the form of a promissory note payable by Wapiti, which was repaid in full during the second quarter of 2012, and (ii) transferred to Wapiti an undivided 50% of our interest in certain of our Uinta Basin non-producing oil and gas assets in exchange for, among other agreements, Wapiti’s commitment to fund $30.0 million of the drilling and completion costs associated with the exploration and development of the subject assets.
In addition, as part of the Uinta Basin Transaction, Gasco Production Company entered the Development Agreement with Wapiti, which includes terms and conditions of a drilling program to develop the subject properties. The following aspects of this joint venture could materially impact Gasco:
· The development of these properties is subject to the terms and conditions of the Development Agreement with Wapiti, and we no longer have the flexibility to control the development of these properties. For example, the Development Agreement sets forth required capital expenditure programs that each party must participate in unless the parties mutually agree to change such programs. If we are not able to pay our share of the costs, we may lose certain rights granted under the Development Agreement and related operating agreements, including the right to continue as operator or contract operator of the properties, the right to make proposals or elect to participate in operations under the Development Agreement or any operating agreement, the right to call, attend and vote at meetings of the operating committee, the right to transfer our interest in the properties and the joint venture, the right to acquire Wapiti’s interest in the properties under the right of first offer provisions of the Development Agreement and the right to acquire its pro rata share of additional properties acquired by Wapiti within the area of mutual interest identified in the Development Agreement. If we do not timely meet our financial commitments under the Development Agreement, our rights to participate in the joint venture will be adversely affected. In addition, each joint venture party has the right to elect to participate in acreage acquisitions in certain a defined area of mutual interest.
· The Development Agreement assigns to each party designated areas over which that party will manage and control operations. We could incur liability as a result of action taken by our joint venture partner.
· In exchange for an undivided 50% of our interest in our Uinta Basin non-producing oil and gas assets, Wapiti has made a commitment to fund $30.0 million of the drilling and completion costs associated with the exploration and development of the subject assets, including the payment of $15 million of costs to be paid on our behalf. Thus, the benefits we anticipate receiving in the joint venture depends in part upon the rate at which new wells are drilled and developed in the joint venture, which could fluctuate significantly from period to period. Moreover, the performance of these third party obligations is outside of our control. The inability or failure of Wapiti to pay its funding commitment, including costs to be paid on our behalf during the drilling term, could increase our costs of operations or result in reduced drilling and production of oil and gas or loss of rights to develop the oil and gas properties held by the joint venture.
· The Development Agreement prohibits any transfer of our interests in the joint venture assets, prior to the end of the drilling term, unless Wapiti consents in its sole discretion. These restrictions may preclude transactions that could be beneficial to our shareholders.
· Disputes between us and our joint venture partner may result in litigation or arbitration that would increase our expenses, delay or terminate projects and distract our officers and directors from focusing their time and effort on our business.
A failure by our gathering, transportation or processing facilities to perform its obligations under our natural gas gathering, transportation and processing agreements may negatively affect our ability to deliver our natural gas production for sale.
Pursuant to the Amended and Restated Monarch Agreement, a gas gathering agreement, we rely on Monarch to gather and deliver our natural gas production from wellheads to points of sale. Additionally, pursuant to the gas gathering agreement, Monarch is required to connect to the gathering system future
wells that we drill within an area of mutual interest established thereunder. Pursuant to the QPC Transportation Agreement, we rely on QPC to transport our natural gas production, and pursuant to the Chipeta Processing Agreement, we rely on Chipeta to process our natural gas production. Any failure by Monarch, QPC or Chipeta, or any successor thereto to timely perform its obligations under the applicable agreements may limit our ability to deliver production into the interstate pipeline where it is sold. A delay or reduction in the amount of natural gas that we sell as a result of a failure by Monarch, QPC or Chipeta to timely perform their obligations could have a material adverse effect on our business, financial condition or results of operations.
During the year ended December 31, 2012, the Amended and Restated Monarch Agreement covered the gathering, processing, compressing and delivery of our gross production of natural gas from all of our Utah acreage from wellheads to points of sale. Our agreement with Monarch was modified upon the commencement of the Chipeta Processing Agreement. Since the beginning of the primary term of the Chipeta Processing Agreement, Chipeta has provided all of our natural gas processing services, and Monarch has not processed any of our natural gas. Monarch and QPC continue to gather and transport our natural gas. Please read “2012 and Recent Highlights-Gas Processing Agreements” in “Item 1.-Business.”
Our ability to market the oil and natural gas that we produce is essential to our business. Pipeline constraints may limit our ability to sell production and may negatively affect the price at which we sell our production, which could have an adverse impact on our results of operations and financial condition.
Several factors beyond our control may adversely affect our ability to market the oil and gas that we discover. These factors include the proximity, capacity and availability of oil and gas pipelines and processing equipment, market fluctuations of prices, taxes, royalties, land tenure, allowable production and environmental protection. The extent of these factors cannot be accurately predicted, but any one or a combination of these factors may result in our inability to sell our oil and gas at prices that would result in an adequate return on our invested capital.
We currently distribute the natural gas that we produce through a single interstate pipeline. Any constraints on the capacity of this pipeline could adversely affect our ability to sell production and, in certain circumstances, may limit our ability to sell any or all of our production in a given period. If this pipeline were to become unavailable, we would incur additional costs to secure a substitute facility in order to deliver the gas that we produce. In addition, although we currently have access to firm transportation for the majority of our current gas production, there is no assurance that we will be able to procure additional transportation on terms satisfactory to us, or at all, if we increase our production through our drilling program or acquisitions.
Because we do not own or operate any natural gas lines or distribution facilities, we rely on third parties to construct additional interstate pipelines to increase our ability to bring our production to market. Any significant change affecting these facilities or our failure to obtain timely access to existing or future facilities on acceptable terms could restrict our ability to conduct normal operations. Delays in the commencement of operations of new pipelines, the unavailability of the new pipelines or other facilities due to market conditions, mechanical reasons or otherwise could have an adverse impact on our results of operations and financial condition. Pipeline capacity constraint could also lead to heightened price competition on such pipeline, which would reduce the price at which we are able to sell the production that does flow. A reduction in the amount of natural gas that we can sell or the price at which such natural gas can be sold could have a material adverse effect on our business, financial condition or results of operations.
Further, interstate transportation and distribution of natural gas is regulated by the federal government through the Federal Energy Regulatory Commission (“FERC”). FERC sets rules and carries out administratively the oversight of interstate markets for natural gas and other energy policy. Additionally, state regulators have powers over sale, supply and delivery of natural gas and oil within their state borders. While we do employ certain companies to represent our interests before state regulatory agencies, our interests may not receive favorable rulings from any state agency, or some future occurrence may drastically alter our ability to enter into contracts or deliver natural gas to the market.
Approximately 6% of our proved reserves are classified as proved developed non-producing and may ultimately prove to be less than estimated.
At December 31, 2012, approximately 6% of our total proved reserves were classified as proved developed non-producing. It will take substantial capital to recomplete or drill our non-producing reserves. Our estimate of proved reserves at December 31, 2012 assumes that we will spend an estimated $0.9 million in future development costs in 2013 to develop these reserves. As described previously, there is substantial doubt regarding our ability to generate sufficient cash flows from operations to fund our ongoing operations, and we currently anticipate that cash on hand and forecasted cash flows from operations will only be sufficient to fund cash requirements for working capital, including debt payment obligations, through the second quarter of 2013. These factors raise substantial doubt about our ability to continue as a going concern. Our drilling plans will be adjusted or completely terminated if we do not have adequate cash flow to fund these projects. For example, we have not allocated any amounts to the 2013 capital budget. Further, our drilling efforts may be delayed or unsuccessful and actual reserves may prove to be less than reserve estimates, which could have a material adverse effect on our financial condition, future cash flows and results of operations.
Our proved reserves are estimates and depend on many factors and assumptions, including various assumptions that are based on conditions in existence as of the dates of the estimates that may turn out to be inaccurate. Any material inaccuracies in these in these reserve estimates or underlying assumptions could cause the quantity and value of our oil and gas reserves, and our revenue, profitability, and cash flow, to be materially different from our estimates.
Estimating accumulations of natural gas and oil is complex and inexact because of the numerous uncertainties inherent in the process. The process relies on interpretations of available geological, geophysical, engineering, production and other technical data the extent, quality and reliability of which can vary. The process also requires certain economic assumptions, some of which are mandated by the SEC. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of reserves.
There are many uncertainties inherent in estimating natural gas and oil reserves and their values, many of which are beyond our control. Estimates of economically recoverable natural gas or oil reserves and of future net cash flows necessarily depend on many variables and assumptions, such as:
· historical natural gas or oil production from that area, compared with production from other producing areas;
· assumptions concerning the effects of regulations by governmental agencies;
· assumptions concerning future prices;
· assumptions concerning future operating costs;
· assumptions concerning severance and excise taxes; and
· assumptions concerning development costs and workover and remedial costs.
Actual future production, gas and oil prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable gas and oil reserves most likely will vary from our estimates. Any significant variance could materially affect the quantities and present value of our reserves. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development and prevailing gas and oil prices. Our reserves may also be susceptible to drainage by operators on adjacent properties.
For these reasons, estimates of the economically recoverable quantities of natural gas or oil attributable to any particular group of properties, classifications of those reserves based on risk recovery and estimates of the future net cash flows expected from them prepared by different engineers, or by the same engineer at different times may vary substantially. Because of this, our reserve estimates may materially change at any time.
The most accurate method of determining proved reserve estimates is based upon a decline analysis method, which consists of extrapolating future reservoir pressure and production from historical pressure decline and production data. The accuracy of the decline analysis method generally increases with the length of the production history. Since most of our wells had been producing for less than ten years as of December 31, 2012, their production history is relatively short, so other (generally less accurate) methods such as volumetric analysis and analogy to the production history of wells of other operators in the same reservoir were used in conjunction with the decline analysis method to determine our estimates of proved reserves as of December 31, 2012. As our properties are produced over time and more data is available, the estimated proved reserves will be redetermined on an annual basis and may be adjusted based on that data. These adjustments could result in downward revisions of our reserve estimates.
It should not be assumed that the present value of future net cash flows included herein is the current market value of our estimated proved oil and gas reserves. In accordance with SEC requirements, we base the estimated discounted future net cash flows from proved reserves on the unweighted arithmetic average of the first-day-of-the-month commodity prices for the trailing twelve months and development and production costs on the date of estimate. Actual future prices and costs may be materially higher or lower than the prices and costs as of the date of the estimate. This price and rate are not necessarily the most appropriate price or discount factor based on prices and interest rates in effect from time to time and risks associated with our reserves or the natural gas and oil industry in general. Current or actual future prices and costs may be materially higher or lower. Actual future net cash flows also will be affected by factors such as:
· the amount and timing of actual production;
· supply and demand for natural gas or oil;
· actual prices received for natural gas in the future being different than those used in the estimate;
· curtailments or increases in consumption of natural gas or oil;
· changes in governmental regulations or taxation; and
· the timing of both production and expenses in connection with the development and production of natural gas or oil properties.
The exploration and development of oil and natural gas properties involves substantial risks that may materially and adversely affect us.
Our future success will largely depend on the success of our exploration drilling program. The business of exploring for and producing oil and natural gas involves a substantial risk of investment loss that even a combination of experience, knowledge and careful evaluation may not be able to overcome. Drilling oil and gas wells involves the risk that the wells will be unproductive or that, although productive, the wells do not produce oil and/or gas in economic quantities. The cost of drilling, completing and operating wells is often uncertain, and drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including, but not limited to:
· unexpected drilling conditions;
· blowouts, fires or explosions with resultant injury, death or environmental damage;
· pressure or irregularities in formations;
· equipment failures or accidents;
· adverse weather conditions;
· compliance with governmental requirements and laws, present and future; and
· shortages or delays in the availability of drilling rigs or water for hydraulic fracturing and the delivery of equipment.
A productive well may become uneconomic in the event water or other deleterious substances are encountered, which impair or prevent the production of oil and/or gas from the well. In addition, production from any well may be unmarketable if it is contaminated with water or other deleterious substances. Furthermore, our operations are conducted in the Rocky Mountain region of the United States. The weather in this area can be extreme and can cause interruption in our exploration and production operations. Severe weather can result in damage to our facilities entailing longer operational interruptions and significant capital investment. Additionally, our operations are subject to disruption from winter storms and severe cold, which can limit operations involving fluids and impair access to our facilities.
If we experience any one or more of these risks, our business, financial condition and results of operations could be materially and adversely affected.
Natural gas and oil reserves are depleting assets, and the failure to replace our reserves would adversely affect our production and cash flows.
Our future natural gas and oil production depends on our success in finding or acquiring new reserves. If we fail to replace reserves, our level of production and cash flows would be adversely impacted. Production from natural gas and oil properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics. Our total proved reserves will decline as reserves are produced unless we conduct successful exploration and development activities and/or acquire properties containing proved reserves. Our ability to make the necessary capital investment to maintain or expand our asset base of natural gas and oil reserves has recently been impaired because of a decline in cash flow from operations and external sources of capital are currently limited or unavailable. Further, we may not be
successful in exploring for, developing or acquiring additional reserves, which could have a material adverse effect on our financial condition, future cash flows and results of operations.
Delays in obtaining drilling permits could have a material adverse effect on our ability to develop our properties in a timely manner.
The average processing time at the BLM in Vernal, Utah for an application to drill on federal leases has been increasing and currently is approximately 24 months or longer. Approximately 80% of our gross acreage in Utah is located on federal leases. If we are delayed in procuring sufficient drilling permits for our federal properties, we may shift more of our drilling in Utah to our state leases, the permits for which require an average processing time of approximately 60 days. While such a shift in resources would not necessarily affect the rate of growth of our cash flow, it would result in a slower growth rate of our total proved reserves, because a higher percentage of the wells drilled on the state leases would be drilled on leases to which proved undeveloped reserves may already have been attributed. Additionally, if the development of our acreage located on federal lands is delayed significantly by the permitting process, we may have to operate at a loss for an extended period of time. Such delays could result in impairments of the carrying value of our unproved properties and could impact the ceiling test calculation.
We may have difficulty managing any growth in our business.
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. If we expand our activities 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 recruitment and retention of experienced managers, geoscientists and engineers, could have a material adverse effect on our business, financial condition and results of operations and our ability to timely execute our business plan.
Technological changes could affect our operations.
The natural gas and oil industry is characterized by rapid and significant technological advancements and introductions of new products and services utilizing new technologies. As others use or develop new technologies, we may be placed at a competitive disadvantage, and competitive pressures may force us to implement such new technologies at substantial costs, some of which we may be unable to bear due to our current liquidity position. In addition, many other natural gas and oil companies have greater financial, technical and personnel resources that may allow them to enjoy technological advantages and may in the future allow them to implement new technologies before we can. We may be unable to respond to such competitive pressures and implement such technologies on a timely basis or at an acceptable cost. If one or more of the technologies that we currently use or may implement in the future were to become obsolete or if we are unable to use the most advanced commercially available technology, it could have a material adverse effect on our financial condition, future cash flows and results of operations.
Competition in the natural gas and oil industry is intense. Our competitors may have greater resources which could enable them to pay a higher price for properties and to better withstand periods of low market prices for hydrocarbons.
The petroleum and natural gas industry is intensely competitive, and we compete with other companies with greater resources. This disparity is currently exacerbated due to our current liquidity position. Many of these companies not only explore for and produce petroleum and natural gas but also carry on refining operations and market petroleum and other products on a regional, national or worldwide basis. Many of
our competitors are large, well-established companies that have a substantially larger operating staff and greater capital resources than we do and, in many instances, have been engaged in the natural gas and oil business for a much longer time than we have. These companies may be able to pay more for exploratory prospects and productive natural gas and oil properties and may be able to define, evaluate, bid for and purchase more properties and prospects than our financial and human resources permit. As a result, we may have difficulty acquiring additional acreage and/or projects, and may have difficulty arranging for the transportation of the oil or natural gas we produce when compared with our larger and better capitalized competitors. We also face competition in obtaining natural gas and oil drilling rigs and in providing the manpower to operate them, as well as providing related services. Our competitors may be able to spend more on the existing and changing technologies that we believe are and will be increasingly important to the current and future success of natural gas and oil companies. In addition, such companies may have a greater ability to continue exploration activities during periods of low hydrocarbon market prices. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. Increased competitive pressure could have a material adverse effect on our financial condition, future cash flows and results of operations.
Acquisition prospects are difficult to assess and may pose additional risks to our operations.
Where appropriate, we may evaluate and pursue acquisition opportunities on terms our management considers favorable. The successful acquisition of natural gas and oil properties requires an assessment of:
· recoverable reserves;
· exploration potential;
· future natural gas and oil prices;
· operating costs;
· potential environmental and other liabilities; and
· permitting and other environmental authorizations required for our operations.
In connection with such an assessment, we would expect to perform a review of the subject properties that we believe is generally consistent with industry practices. Nonetheless, the resulting conclusions are inexact and their accuracy inherently uncertain, and such an assessment may not reveal all existing or potential problems, nor will it necessarily permit a buyer to become sufficiently familiar with the properties to fully assess their merits and deficiencies. Inspections may not always be performed on every facility or well, and structural and environmental liabilities, such as, for example, subsurface ground water contamination, are not necessarily observable even when an inspection is undertaken. Future acquisitions could pose additional risks to our operations and financial results, including:
· problems integrating the purchased operations, personnel or technologies;
· unanticipated costs;
· diversion of resources and management attention from our exploration business;
· entry into regions or markets in which we have limited or no prior experience; and
· potential loss of key employees, particularly those of the acquired organization.
We may suffer losses or incur liability for events that we have, or that the operator of a property has, chosen not to insure against.
The natural gas and oil business involves many operating hazards, such as:
· well blowouts, fires and explosions;
· surface craterings and casing collapses;
· uncontrollable flows of natural gas, oil or well fluids;
· pipe and cement failures;
· formations with abnormal pressures;
· stuck drilling and service tools;
· pipeline and tank ruptures or spills;
· natural disasters; and
· releases of toxic natural gas.
Any of these events could cause substantial losses to us as a result of:
· injury or death;
· damage to and destruction of property, natural resources and equipment;
· pollution and other environmental damage;
· regulatory investigations and penalties;
· suspension of operations; and
· repair and remediation costs.
Insurance against every operational risk is not available at economic rates. We may suffer losses from hazards that we cannot insure against or that we have, or the operator thereof has, chosen not to insure against because of high premium costs or other reasons. We could also be responsible for environmental damage caused by previous owners of property from whom we purchased leases. As a result, we may incur substantial liabilities to third parties or governmental entities. If these liabilities are not covered by our insurance, paying them could reduce or eliminate the funds available for exploration, development or acquisitions or result in the loss of our properties. The payment of any such liabilities may have a material adverse effect on our business, financial condition and results of operations.
We may incur losses 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 a petroleum and natural gas lease that has been purchased in error from a person who is not the owner of the mineral interest desired, our interest would be worthless. In such an instance, the amount paid for such petroleum and natural gas lease or leases would be lost.
It is our practice in acquiring petroleum and natural gas leases or undivided interests in petroleum and natural gas leases not to undergo the expense of retaining lawyers to examine the title to the mineral interest to be placed under lease or already placed under lease. Rather, we will rely upon the judgment of petroleum and natural gas lease brokers or landmen who perform the fieldwork in examining records in the appropriate governmental office before attempting to acquire a lease in a specific mineral interest.
If there are any title defects in the properties in which we hold an interest, we may not be able to proceed with our exploration and development of the lease site or may suffer a monetary loss, including as a result of performing any necessary curative work prior to the drilling of a petroleum and natural gas well.
Our operations could be adversely impacted by security breaches, including cyber-security breaches, which could affect our production of oil and natural gas or could affect other parts of our business.
We face security exposure, including cyber-security exposure, from unauthorized access to our facilities and computer systems. This exposure includes unauthorized access to sensitive information; malicious damage to our facilities, infrastructure, and computer systems; malicious damage to third-party facilities, infrastructure, and computer systems; safety exposure for our employees and contractors; and disruptions of our operations. Although we utilize various procedures and controls to mitigate these exposures, there can be no assurances that these procedures and controls will be sufficient to prevent such events from occurring. Cyber-security exposures in particular are evolving and include malicious software, unauthorized access to confidential data and disruptions to operations that use computers and data systems. We do not carry business interruption insurance. Any of these security breaches could have a material adverse affect on our consolidated financial position, results of operations and cash flows.
Because our reserves and production are concentrated in a small number of properties in one primary geographic location, production problems or significant changes in reserve estimates related to any property could have a material impact on our business.
Our reserves and production primarily come from a small number of producing properties in Utah. If mechanical problems with the wells or production facilities (including salt water disposal, pipelines, compressors and processing plants), depletion, weather or other events adversely affect any particular property, we could experience a significant decline in our production, which could have a material adverse effect on our cash flows, financial condition and results of operations. In addition, if the actual reserves associated with any one of our properties are less than estimated, our overall reserve estimates could be materially and adversely affected.
Shortages of supplies, equipment and personnel may adversely affect our operations.
The natural gas and oil industry is cyclical and, from time to time, there are shortages of drilling rigs, equipment, supplies or qualified personnel. During these periods, the costs of rigs, equipment and supplies may be substantially increased and their availability may be limited. In addition, the demand for, and wage rates of, qualified personnel, including drilling rig crews, may rise as the number of rigs in service increases. We do not have a drilling rig under contract at this time. If drilling rigs, equipment, supplies or qualified personnel are unavailable to us due to excessive costs or demand or otherwise, our
ability to execute our exploration and development plans could be materially and adversely affected and, as a result, our business, financial condition and results of operations could be materially and adversely affected.
Our success depends on our key management personnel, the loss of any of whom could disrupt our business.
The success of our operations and activities is dependent to a significant extent on the efforts and abilities of our management. The loss of services of any of our key managers - including Mr. Grant, our President and Chief Executive Officer, Mr. Decker, our Executive Vice President and Chief Operating Officer and Ms. Herald, our Vice President and Chief Accounting Officer-could have a material adverse effect on our business, financial condition and results of operations. We have not obtained “key man” insurance for any of our management.
Our directors are engaged in other businesses which may result in conflicts of interest.
Certain of our directors also serve as directors of other companies or have significant shareholdings in other companies operating in the oil and gas industry. Our Chairman, Charles Crowell, also serves on the Board of Directors of Derek Oil & Gas Corporation. King Grant, our President, Chief Executive Officer and director is a member of the Board of Directors of Battalion Energy. Richard S. Langdon, another one of our directors, is President and Chief Executive Officer of KMD Operating Company LLC, a private exploration and production company active in onshore California. Mr. Langdon is also the President and Chief Executive Officer of Sigma Energy Ventures with E&P activities in the Texas Gulf Coast. Further, Mr. Langdon is a member of the Board of Directors of Constellation Energy Partners LLC (“CEP”), a public limited liability company focused on the acquisition, development and exploitation of oil and natural gas properties and related midstream assets. CEP’s activities are currently focused in the Black Warrior Basin of Alabama and in the Cherokee Basin in Oklahoma and Kansas. Another of our directors, Richard Burgess, serves on the Board of Michigan Oil and Gas Association and Potential Gas Committee. We estimate that all of our outside directors spend up to 10% of their time on our business.
To the extent that such other companies participate in ventures in which we may participate, or compete for prospects or financial resources with us, these officers and directors will have a conflict of interest in negotiating and concluding terms relating to the extent of such participation. In the event that such a conflict of interest arises at a meeting of the board of directors, a director who has such a conflict must disclose the nature and extent of his interest to the board of directors and abstain from voting for or against the approval of such participation or such terms.
In accordance with the laws of the State of Nevada, our directors are required to act honestly and in good faith with a view to our best interests. In determining whether or not we will participate in a particular program and the interest therein to be acquired by us, the directors will primarily consider the degree of risk to which we may be exposed and our financial position at that time.
Certain U.S. federal income tax deductions currently available with respect to oil and natural gas exploration and development may be eliminated as a result of future legislation.
Legislation has been proposed that would, if enacted into law, make significant changes to U.S. federal income tax laws, including the elimination of certain key U.S. federal income tax incentives currently available to oil and natural gas exploration and production companies. These proposed changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and natural gas properties; (ii) the elimination of current deductions for intangible drilling and development costs; (iii) the elimination of the deduction for certain domestic production activities; and (iv) an extension of the amortization period for certain geological and geophysical expenditures. It is unclear whether these or
similar changes will be enacted and, if enacted, how soon any such changes could become effective. The passage of any legislation as a result of these proposals or any other similar changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that are currently available with respect to oil and natural gas exploration and development, and any such change could increase our taxable income and negatively impact the value of an investment in us.
We are subject to complex governmental laws and regulations which may expose us to significant costs and liabilities and adversely affect the cost, manner or feasibility of conducting our business.
Our petroleum and natural gas exploration and production interest and operations are subject to stringent and complex federal, state and local laws and regulations relating to the operation and maintenance of our facilities, including laws regulating removal of natural resources from the ground and the discharge of materials into the environment and otherwise relating to environmental protection. Oil and natural gas operations are also subject to federal, state, provincial and local laws and regulations which seek to maintain health and safety standards by regulating the design and use of drilling methods and equipment. We may be required to make large expenditures to comply with these regulatory requirements. Legislation affecting the petroleum and natural gas industry is under constant review for amendment and expansion. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue and have issued rules and regulations binding on the petroleum and natural gas industry, some of which carry substantial penalties for failure to comply. Any increases in the regulatory burden on the petroleum and natural gas industry created by new legislation would increase our cost of doing business and adversely affect our profitability.
Failure to comply with these laws and regulations applicable to our interests and operations could result in the assessment of administrative, civil and criminal penalties, the imposition of investigatory or remedial obligations, and the issuance of orders enjoining or limiting some or all of our operations, any of which could have a material adverse effect on our financial condition. Legal requirements are sometimes unclear or subject to reinterpretation and may be frequently changed in response to economic or political conditions. As a result, it is hard to predict the ultimate cost of compliance with these requirements or their effect on our interests and operations. In addition, existing laws or regulations, as currently interpreted or reinterpreted in the future, or future laws or regulations may have a material adverse effect on our financial condition, future cash flows and results of operations.
Climate change legislation and regulatory initiatives restricting emissions of GHGs could result in increased operating costs and reduced demand for the oil and natural gas we produce.
In December 2009, the EPA determined that emissions of GHG present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. Based on these findings, the EPA has adopted regulations under existing provisions of the CAA that establish PSD and Title V permit reviews for GHG emissions from certain large stationary sources. Facilities required to obtain PSD permits for their GHG emissions also will be required to meet “best available control technology” standards that will be established by the states or, in some cases, by the EPA on a case-by-case basis. The EPA has also adopted rules requiring the monitoring and reporting of GHG emissions from specified sources in the United States, including, among others, certain oil and natural gas production facilities on an annual basis, which includes certain of our operations.
While Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of adopted legislation to reduce GHG emissions at the federal level in recent years. In the absence of such federal climate legislation, a number of state and regional efforts,
including a GHG cap-and-trade program adopted by California, have emerged that are aimed at tracking and/or reducing GHG emissions by means of cap and trade programs that typically require major sources of GHG emissions, such as electric power plants, to acquire and surrender emission allowances in return for emitting those GHGs. If Congress undertakes comprehensive tax reform in the coming year, it is possible that such reform may include a carbon tax, which could impose additional direct costs on operations and reduce demand for refined products. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any such future laws and regulations that require reporting of GHGs or otherwise limit emissions of GHGs from our equipment and operations could require us to incur costs to monitor and report on GHG emissions or reduce emissions of GHGs associated with our operations, and such requirements also could adversely affect demand for the oil and natural gas that we produce.
Federal, state and local legislative and regulatory initiatives relating to hydraulic fracturing as well as governmental reviews of such activities could result in increased costs and additional operating restrictions or delays in the completion of oil and natural gas wells and adversely affect our production.
Hydraulic fracturing is an essential and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations such as shales. We expect to use hydraulic fracturing techniques in many of our future natural-gas drilling programs. The process involves the injection of water, proppants, and additives under pressure into a targeted subsurface formation. The water and pressure create fractures in the rock formations, which are held open by the proppants, such as sand, enabling the oil or natural gas to flow to the wellbore. The process is typically regulated by state oil and natural gas commissions, but the EPA has asserted federal regulatory authority under the SDWA over hydraulic fracturing activities involving diesel fuel published draft permitting guidance in May 2012 addressing the performance of such activities using diesel fuels. In November 2011, the EPA announced its intent to develop and issue regulations under the Toxic Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing and the agency currently plans to issue a Notice of Proposed Rulemaking that would seek public input on the design and scope of such disclosure regulations. In addition, Congress has from time to time considered the adoption of legislation to provide for federal regulation of hydraulic fracturing under the SDWA and to require disclosure of the chemicals used in the hydraulic fracturing process. Some states have adopted, and other states are considering adopting legal requirements that could impose more stringent permitting, public disclosure or well construction requirements on hydraulic fracturing activities. Local government also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular. If new or more stringent federal, state or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells.
In addition, certain governmental reviews have been conducted or are underway that focus on environmental aspects of hydraulic fracturing practices. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with a first progress report outlining work currently underway by the agency released on December 21, 2012 and a final report drawing conclusions about the potential impacts of hydraulic fracturing on drinking water resources expected to be available for public comment and peer review by 2014. Moreover, the EPA has announced that it will develop effluent limitations for the treatment and discharge of wastewater resulting from hydraulic fracturing activities by 2014. Other governmental agencies, including the U.S. Department of Energy and the U.S. Department of the Interior, have evaluated or are evaluating various other aspects of hydraulic fracturing. These ongoing or proposed studies,
depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the federal SDWA or other regulatory mechanisms.
Our operations are subject to environmental and occupational health and safety laws and regulations that may expose us to significant costs and liabilities.
Our oil and natural gas exploration and production operations are subject to stringent and comprehensive federal, regional, state and local laws and regulations governing occupational health and safety aspects of our operations, the discharge of materials into the environment, or otherwise relating to environmental protection. These laws and regulations may impose numerous obligations applicable to our operations including the acquisition of a permit before conducting drilling or other regulated activities; restriction of types, quantities and concentration of materials that can be released into the environment; limitation or prohibition of drilling activities on certain lands lying within wilderness, wetlands and other protected areas; application of specific health and safety criteria addressing worker protection; and imposition of substantial liabilities for pollution resulting from our operations. Numerous governmental authorities, such as the EPA, and analogous state agencies have the power to enforce compliance with these laws and regulations and the permits issued under them, oftentimes requiring difficult and costly compliance or corrective actions. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil or criminal penalties, the imposition of investigatory or remedial obligations and the issuance of orders limiting or prohibiting some or all of our operations.
There is inherent risk of incurring significant environmental costs and liabilities in the performance of our operations as a result of our handling of petroleum hydrocarbons and wastes, because of air emissions and wastewater discharges related to our operations and due to historical industry operations and waste disposal practices. Under certain environmental laws and regulations, we could be subject to joint and several, strict liability for the removal or remediation of previously released materials or property contamination regardless of whether we were responsible for the release or contamination or if the operations were not in compliance with all applicable laws at the time those actions were taken. Private parties, including the owners of properties upon which our wells are drilled and facilities where our petroleum hydrocarbons or wastes are taken for reclamation or disposal, also may have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property or natural resource damages. In addition, the risk of accidental spills or releases could expose us to significant liabilities that could have a material adverse effect on our business, financial condition or results of operations. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly well drilling, construction, completion or water management activities, or waste control, handling, storage, transport, disposal or cleanup requirements could require us to make significant expenditures to attain and maintain compliance and may otherwise have a material adverse effect on our own results of operations, competitive position or financial condition. We may not be able to recover some or any of these costs from insurance. Please read “Governmental Regulations and Environmental Laws” in “Item 1.-Business.”
Current and future economic conditions in the United States and key international markets may materially adversely impact our operating results.
Our operations are affected by local, national and international economic conditions and the condition of the natural gas and oil industry. The United States and other world economies are slowly recovering from a recession, which began in 2008. Although growth has resumed, it is modest and certain economic data indicates the United States and worldwide economies may require some time to recover. There are likely to be significant long-term effects resulting from the recession and credit market crisis, including a future global economic growth rate that is slower than what was experienced in recent years. In addition, more volatility may occur before a sustainable, yet lower, growth rate is achieved. Global economic growth
drives demand for energy from all sources, including fossil fuels. A lower future economic growth rate will result in decreased demand growth for our natural gas production and oil, as well as lower commodity prices, which will reduce our cash flows from operations and our profitability.
Market deterioration could also jeopardize the performance of certain counterparty obligations, including those of our insurers and customers. Although we assess the creditworthiness of our counterparties, prolonged business decline or disruptions as a result of economic slow down or lower commodity prices could lead to changes in a counterparty’s liquidity and increase our exposure to credit risk and bad debts. In the event any such party fails to perform, our financial results could be adversely affected and we could incur losses and our liquidity could be negatively impacted.
Risks Related to Our Capital Stock
Our common stock has experienced, and may continue to experience, price volatility and low trading volume.
The trading price of our common stock has been and may continue to be subject to large fluctuations and has traded at a low price per share for a substantial period of time, which may result in losses to investors. In addition, on December 6, 2012, we received a notice from the Exchange indicating that we do not satisfy the continued listing standards of the Exchange as a result of the low price per share. The Exchange predicates our continued listing on the Exchange on us effecting a reverse stock split of our common stock by June 6, 2013. We also received a notice from the Exchange on January 11, 2013 indicating that we do not satisfy the continued listing standards in connection with sustained losses or impaired financial condition. Please read “Item 1.-Business-2012 and Recent Highlights- NYSE MKT LLC Communications” above for more information.
Our stock price may increase or decrease in response to a number of events and factors, including:
· the results of our exploratory drilling;
· trends in our industry and the markets in which we operate;
· our ability to remain in compliance with our operational agreements, including our gas processing, gathering and transportation agreements;
· changes in the market price of the commodities we sell;
· changes in financial estimates and recommendations by securities analysts;
· acquisitions and financings;
· quarterly variations in operating results;
· the operating and stock price performance of other companies that investors may deem comparable to us;
· an inability to regain and maintain compliance with the listing requirements of the Exchange; and
· issuances, purchases or sales of blocks of our common stock.
This volatility may adversely affect the price of our common stock regardless of our operating performance. See “Item 5.-Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities” for further discussion.
A substantial number of shares of our common stock will be eligible for future sale upon conversion of the 2015 Notes (or shares of preferred stock issuable upon conversion of the 2015 Notes), and the sale of those shares could adversely affect our stock price. Our stockholders will experience substantial dilution if the 2015 Notes are converted.
The 2015 Notes are convertible, at the option of the holder, at any time prior to maturity, into shares of common stock or, at the election of such holder, into shares of preferred stock, which are convertible into common stock. Pursuant to the terms of the Exchange Agreements entered into in connection with the issuance of the 2015 Notes (or shares of preferred stock issuable upon conversion of the 2015 Notes) we listed an additional 21,433,135 shares of common stock on the Exchange. The initial conversion price for converting the 2015 Notes into common stock is equal to $0.60 per share of common stock, which is equal to a conversion rate of 1,666.6667 shares of common stock per $1,000 principal amount of 2015 Notes. The conversion rate is subject to adjustment in certain circumstances and limitations. The initial conversion price for converting the 2015 Notes into preferred stock (with certain exceptions), is equal to $100, which is equal to a conversion rate of ten shares of preferred stock per $1,000 principal amount of 2015 Notes.
Specifically, the 2015 Notes and preferred stock entitle the holders thereof to voluntarily convert such securities at any time into an aggregate principal amount of approximately 107.1 million shares of common stock. In September 2010, 30% of the 2015 Notes were automatically converted into an aggregate amount of 305,754 shares of preferred stock, which were convertible into an aggregate of approximately 51.0 million shares of common stock. As of December 31, 2012, we have 182,065 shares of preferred stock outstanding which are convertible into approximately 30.3 million shares of common stock. Any shares of common stock issued upon conversion of the 2015 Notes or preferred stock will result in significant dilution to our existing stockholders.
Additionally, all of the shares of common stock issued upon conversion of the 2015 Notes and preferred stock are immediately eligible for resale in the public markets under Rule 144 of the Securities Act. If a significant portion of these shares were to be offered for sale at any given time, the public market for our common stock and the value of our common stock owned by our stockholders could be adversely affected. Any such sales, or the anticipation of the possibility of such sales, could depress the market price of our common stock.
If our outstanding warrants are exercised, our stock price could be adversely affected and our stockholders may experience substantial dilution.
In 2011, we issued warrants (“Warrants”) to purchase up to an aggregate of 30,250,000 shares of common stock are exercisable, at the option of the holder, subject to the terms of Warrants. The Warrants are exercisable immediately for a term of sixty months, beginning at issuance, at an initial exercise price of $0.35 per share, however, the exercise price and number of shares of common stock issuable on exercise of the Warrants are subject to adjustment in the event of any stock split, reverse stock split, stock dividend, recapitalization, reorganization or similar transaction. If we make a distribution of our assets to all of our stockholders, holders of the Warrants may be entitled to participate. All of the shares of common stock issued upon exercise of the Warrants are immediately eligible for resale in the public markets. Any such sales, or the anticipation of the possibility of such sales, could depress the market price of our common stock. Additionally, upon issuance shares of common stock upon exercise of the Warrants, if any, our existing stockholders may incur significant dilution of their interests.
Shares eligible for future sale may cause the market price for our common stock to drop significantly, even if our business is doing well.
If our existing shareholders sell our common stock in the market, or if there is a perception that significant sales may occur, the market price of our common stock could drop significantly. In such case, our ability to raise additional capital in the financial markets at a time and price favorable to us might be impaired. In addition, our board of directors has the authority to issue additional shares of our authorized but unissued common and preferred stock without the approval of our shareholders, subject to certain limitations under the rules of the Exchange. Additional issuances of our common stock would dilute the ownership percentage of existing shareholders and may dilute the earnings per share of our common stock. As of December 31, 2012, we had 169,749,981 shares of common stock issued and outstanding, 9,506,943 outstanding options to purchase common stock, 336,000 outstanding shares of unvested restricted stock and outstanding Warrants to purchase 30,250,000 shares of common stock. An additional 11,466,640 shares of common stock are issuable under our long term incentive plan.
Assuming all of our outstanding Warrants, preferred stock, and 2015 Notes are converted at the applicable conversion prices, the number of shares of our common stock outstanding would increase by approximately 135,874,173 shares to approximately 305,624,154 shares (this number assumes no exercise of the options described above and no additional grants of options or restricted stock).
We have not previously paid dividends on our common stock and we do not anticipate doing so in the foreseeable future.
We have not in the past paid, and do not anticipate paying in the foreseeable future, cash dividends on our common stock. Our Indenture contains covenants that restrict our ability to pay dividends on our common stock. Additionally, any future decision to pay a dividend and the amount of any dividend paid, if permitted, will be made at the discretion of our board of directors.
We have anti-takeover provisions in our articles of incorporation and by-laws that may discourage a change of control.
Our articles of incorporation and bylaws contain several provisions that could delay or make more difficult the acquisition of us through a hostile tender offer, open market purchases, proxy contest, merger or other takeover attempt that a stockholder might consider in his or her best interest, including those attempts that might result in a premium over the market price of our common stock.
Under the terms of our articles of incorporation and as permitted under Nevada law, we have elected not to be subject to Nevada’s anti-takeover law. This law provides that specified persons who, together with affiliates and associates, own, or within three years did own, 15% or more of the outstanding voting stock of a corporation cannot engage in specified business combinations with the corporation for a period of three years after the date on which the person became an interested stockholder. With the approval of our stockholders, we may amend our articles of incorporation in the future to become subject to the anti-takeover law. This provision would then have an anti-takeover effect for transactions not approved in advance by our board of directors, including discouraging takeover attempts that a stockholder might consider in his or her best interest or that might result in a premium over the market price for the shares of our common stock.
ITEM 1B.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 2
ITEM 2 - PROPERTIES
Petroleum and Natural Gas Properties
Riverbend Project
The Riverbend Project comprises approximately 114,569 gross acres in the Uinta Basin of northeastern Utah, of which we held interests in approximately 41,077 net acres as of December 31, 2012. Historically, our engineering and geologic focus has been concentrated on natural gas and condensate charged formations in the Uinta Basin: the Green River, Wasatch, Mesaverde, Blackhawk, Mancos, Dakota and Morrison formations. A typical well drilled into these formations may encounter multiple distinct natural gas sands, silts and shales located between approximately 6,000 and 15,000 feet in depth that are completed using up to twelve staged recompletions. As of December 31, 2012, we held an interest in 133 gross (40 net to our interest) producing wells and three gross (one net) shut-in wells located on these properties. For additional information on the operations and recent developments in connection with the Riverbend Project, please see “Item 1.-Business-2012 and Recent Highlights-Green River Oil Wells” above for more information.
Working Interest Acquisition
During December 2012, we acquired additional working interests in 32 producing wells, in the Riverbend area of Utah, in which we have a working interest and operate, for $177,620. The acquired interests range from 4% to 10% per well with an average of 8% per well and represent an estimated increase to our current reserves of approximately 596,000 Mcfe.
Southern California Project
As of December 31, 2012, we had a leasehold interest in approximately 41,716 gross (16,873 net) acres in Kern County in Southern California. For additional information on the operations and recent developments in connection with the Willow Springs, Antelope Valley and Northwest McKittrick, please see “Item 1 - Business-2012 and Recent Highlights-California Projects” above for more information.
Capital Expenditure Budget
It is unclear whether we will have sufficient resources to fund a capital expenditure budget for 2013 and whether we will be able to continue as a going concern. We have not allocated any amounts to the 2013 capital budget. Due to the significant extended decline in the natural gas market and sustained low natural gas prices caused by excess production and stagnant growth in the demand for natural gas, we have not been able to recover our exploration and development costs as anticipated. There is substantial doubt regarding our ability to generate sufficient cash flows from operations to fund our ongoing operations, and we currently anticipate that cash on hand and forecasted cash flows from operations will only be sufficient to fund cash requirements for working capital, including debt payment obligations, through the second quarter of 2013. This expectation is based on various assumptions, including those related to future natural gas and oil prices, production results and the effectiveness of our cash management strategy discussed elsewhere herein, some or all of which may not prove to be correct and may result in our inability to meet cash requirements prior to the second quarter of 2013. See “Item 7.-Management’s Discussion and Analysis of Financial Condition and Results of Operations-Liquidity and Capital Resources.”
Oil and Natural Gas Reserves
Our estimated proved reserves and related future net revenues, PV-10 and standardized measure of discounted future net cash flows at December 31, 2012 were determined using the 12-month unweighted arithmetic average of the first-day-of-the-month price for the period January 2012 through December 2012, and were held constant throughout the life of the properties. These prices, weighted by production over the lives of the proved reserves were $80.25 per Bbl for oil and oil equivalents and $2.15 per Mcf for natural gas.
For more information on our reserves, please read “Production and Reserve Information” in “Item 7.-Management’s Discussion and Analysis of Financial Condition and Results of Operation.”
Company Reserve Estimates
Our proved reserve information as of December 31, 2012 included in this Annual Report was estimated by Netherland, Sewell & Associates, Inc. (“NSAI”), independent petroleum engineers. A copy of NSAI’s summary reserve report is included as Exhibit 99.1 to this Annual Report. See Note 21 - Supplemental Oil and Gas Reserve Information (Unaudited) to the accompanying consolidated financial statements for further discussion. In accordance with SEC guidelines, NSAI’s estimates of future net revenues from our properties, and the pre-tax present value of discounted future net cash flows (“PV-10”) and standardized measure thereof, were determined to be economically producible under existing economic conditions, which requires the use of the 12-month average price for each product, calculated as the unweighted arithmetic average of the first-day-of-the-month price for the period January 2012 through December 2012, except where such guidelines permit alternate treatment, including the use of fixed and determinable contractual price escalations.
The tables below set forth information as of December 31, 2012 with respect to our estimated proved reserves, the associated present value of discounted future net cash flows and the standardized measure of discounted future net cash flows. Neither the PV-10 nor the standardized measure is intended to represent the current market value of the estimated oil and natural gas reserves we own. All of our proved undeveloped reserves as of December 31, 2012 became uneconomic at these prices and as a result were not included in the December 31, 2012 reserve estimates. Our estimate of proved reserves at December 31, 2012 assumes that we will spend an estimated $0.9 million in future development costs in 2013 to develop these reserves. For more information see “Item 7.-Management’s Discussion and Analysis of Financial Condition and Results of Operations-2013 Capital Budget.”
All of our proved reserves are located within the state of Utah.
(a) Present value of discounted future net cash flows represents the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development costs, using the 12-month unweighted arithmetic average of the first-day-of-the-month price for the
period January 2012 through December 2012 and were held constant throughout the life of the properties. The average prices weighted by production over the lives of the proved reserves used in the reserve report were $2.15 per Mcf of gas and $80.25 per Bbl of oil. All of our proved undeveloped reserves became uneconomic at these prices and as a result were not included in the December 31, 2012 reserve estimates. These prices should not be interpreted as a prediction of future prices.
Reserve engineering is a subjective process of estimating underground accumulations of crude oil, condensate and natural gas that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. The quantities of oil and natural gas that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures and future oil and natural gas sales prices may differ from those assumed in these estimates. Therefore, the PV-10 amounts shown above should not be construed as the current market value of the oil and natural gas reserves attributable to our properties.
Non-GAAP Present Value Reconciliation
Management uses discounted future net cash flows, which are calculated without deducting estimated future income tax expenses, and the present value thereof as one measure of the value of our current proved reserves and to compare relative values among peer companies without regard to income taxes. We also understand that securities analysts and rating agencies use this measure in similar ways. While future net revenue and present value are based on prices, costs and discount factors which are consistent from company to company, the standardized measure of discounted future net cash flows is dependent on the unique tax situation of each individual company. PV-10 is considered to be a non-GAAP financial measure; however as of December 31, 2012, the PV-10 and the standardized measure of discounted future net cash flows are equal because the effects of estimated future income tax expenses are zero.
Qualifications of Technical Persons and Internal Controls Over Reserves Estimation Process
Our proved reserve information as of December 31, 2012 included in this Annual Report was estimated by our independent petroleum engineers, NSAI, in accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserve Information promulgated by the Society of Petroleum Engineers and definitions and guidelines established by the SEC. NSAI was founded in 1961 and performs consulting petroleum engineering services under the Texas Board of Professional Engineers Registration No..
Our Executive Vice President and Chief Operating Officer, Michael K. Decker, is the person primarily responsible for overseeing the preparation of our internal reserve estimates and for the coordination of the third-party reserve reports provided by NSAI. Mr. Decker has over 35 years of experience in the oil and gas industry ranging from exploration, development and operations to mergers and acquisitions. He holds a BS degree in Geological Engineering from the Colorado School of Mines. Prior to joining us in 2001, Mr. Decker served as the Vice President of Exploitation of Prima Energy Corporation, a NASDAQ-traded oil and gas company.
Within NSAI, the technical persons primarily responsible for preparing the estimates set forth in the NSAI report are Mr. Craig H. Adams and Mr. William J. Knights. Mr. Adams has been practicing consulting petroleum engineering at NSAI since 1997. Mr. Adams is a Licensed Professional Engineer in the State of Texas (License No. 68137) and has over 26 years of practical experience in petroleum engineering with over 21 years experience in the estimation and evaluation of oil and gas reserves. He graduated from Texas Tech University in 1985 with a Bachelor of Science Degree in Petroleum Engineering. Mr. Knights has been practicing consulting petroleum geology at NSAI since 1991. Mr. Knights is a Licensed Professional Geoscientist in the State of Texas, Geology (License No. 1532) and
has over 32 years of practical experience in petroleum geosciences, with over 22 years experience in the estimation and evaluation of reserves. He graduated from Texas Christian University in 1981 with a Bachelor of Science Degree in Geology and in 1984 with a Master of Science in Geology. Both technical principals meet or exceed the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers, and both are proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines.
The other technical persons responsible for preparing the reserves estimates presented herein meet the requirements regarding qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers.
We also maintain an internal staff of petroleum engineers and geoscience professionals who work closely with NSAI to ensure the integrity, accuracy and timeliness of data furnished to NSAI in their reserves estimation process. In the fourth quarter, our technical team meets regularly with representatives of NSAI to review properties and discuss methods and assumptions used in NSAI’s preparation of the year-end reserves estimates. While we have no formal committee specifically designated to review reserves reporting and the reserves estimation process, a preliminary copy of the NSAI reserve report is reviewed by our audit committee with representatives of NSAI and internal technical staff. Additionally, our senior management reviews and approves any internally estimated significant changes to our proved reserves on a quarterly basis.
Reserve Technologies
Proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil and/or natural gas actually recovered will equal or exceed the estimate. To achieve reasonable certainty, NSAI employed technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and economic data used in the estimation of our proved reserves include, but are not limited to, well logs, geologic maps and available down well and production data, and well test data.
Reserve Sensitivities
The following table discloses information regarding the sensitivity of our estimated proved oil and gas reserves to price fluctuations.
(a) This case represents pricing under SEC rules under which the prices used are the 12-month unweighted arithmetic average of the first-day-of-the-month prices for the period January
2012 through December 2012. The oil and gas prices used in this scenario, weighted by production over the lives of the proved reserves are $80.25 per Bbl of oil and $2.15 per Mcf of gas.
(b) Scenario 1 estimates total proved reserves assuming a 10% price increase in both the oil and the gas price used in the SEC pricing scenario.
(c) Scenario 2 estimates total proved reserves assuming a 10% price decrease in both the oil and the gas price used in the SEC pricing scenario.
Volumes, Prices and Operating Expenses
The following table presents information regarding the production volumes, average sales prices received (excluding the impact of our hedges) and average production costs for the periods presented associated with our sales of natural gas and oil for the periods indicated.
Development, Exploration and Acquisition Capital Expenditures
The following table presents information regarding our net costs incurred in the purchase of proved and unproved properties and in exploration and development activities:
Productive Oil and Gas Wells
The following summarizes our producing and shut-in oil and gas wells as of December 31, 2012.
Oil and Natural Gas Acreage
Exploration and Productive Acreage
The following table sets forth our ownership interest in undeveloped and developed leasehold acreage, in the areas indicated as of December 31, 2012. The table does not include acreage that we have a contractual right to acquire or to earn through drilling projects, or any other acreage for which we have not yet received leasehold assignments. In certain leases, our ownership is not the same for all depths; therefore, the net acres in these leases are calculated using the greatest ownership interest at any depth. Generally this greater interest represents our ownership in the primary objective formation.
Undeveloped Acreage
The following table summarizes our ownership interest in the gross and net undeveloped acreage in the areas indicated that will expire in each of the next three years.
Our acreage positions are maintained by the payment of delay rentals or by the existence of a producing well on the acreage. As of December 31, 2012, approximately 80% of the gross acreage that we hold is located on federal lands, approximately 17% of the acreage is located on state lands and 3% is located on land owned by individuals. It has been our experience that the permitting process related to the
development of acreage on federal lands is more time consuming and expensive than the permitting process related to acreage on state lands. We have generally been able to obtain state permits within 60 days, while obtaining federal permits has taken approximately 24 months or longer. If we are delayed in procuring sufficient drilling permits for our federal properties, we will shift more of our drilling in Utah to our state leases. While such a shift in resources would not necessarily affect the rate of growth of our cash flow, it would result in a slower growth rate of our total proved reserves, because a higher percentage of the wells drilled on the state leases will be drilled on leases to which proved undeveloped reserves may already have been attributed. Additionally, if the development of our acreage located on federal lands is delayed significantly by the permitting process, we may have to operate at a loss for an extended period of time. Such delays could result in impairments of the carrying value of our unproved properties and could impact the ceiling test calculation. During the year ended December 31, 2012, we reclassified approximately $7,942,000 of acreage costs in Utah and California into proved property. This reclassification is comprised of a $7,000,000 decrease in the carrying value of our Utah acreage based upon an independent appraisal as of December 31, 2012 and $942,000 representing the value of leases that expired during 2012. During 2011, we reclassified $660,000 of acreage costs in Nevada into proved property as we relinquished our control over this acreage to another party in exchange for a small overriding royalty interest on any future drilling projects. After these impairments, the aggregate carrying value of our unproved acreage is approximately $31,486,314 as of December 31, 2012.
Drilling Activity
The following table sets forth our drilling activity during the years ended December 31, 2012, 2011 and 2010. As of December 31, 2011, we had two wells in progress and these wells were completed during January 2012.
Delivery Commitments
Pursuant to our Gas Processing Agreement with Chipeta, we dedicated certain of our natural gas production from our acreage in Utah to Chipeta for processing. We reserved 25,000 Mcf/d of capacity in the Chipeta processing plant for cryogenic processing and agreed to pay specified processing fees per MMBtu as well as a pro rata share of all applicable electric compression costs, subject to escalation on an annual basis. The primary term of the Chipeta Processing Agreement began upon the completion of the building of Chipeta’s facility on February 7, 2013. Under this agreement, we are committed to deliver, on average, at least 90% of our contracted cryogenic capacity of 25,000 Mcf/d (the “Minimum Daily Quantity”) during each monthly accounting period. Following the first twelve monthly accounting periods, Chipeta may determine whether we failed to deliver equal to or greater than the Minimum Daily Quantity multiplied by the number of days in the annual accounting period. If we delivered less than the quantity we committed to deliver, we would be required to pay a deficiency payment equal to the
contracted cryogenic processing fee multiplied by the deficient quantity. In addition, to the extent that Chipeta has reasonable grounds for uncertainty regarding the performance of our obligations under our gas processing agreement, including a material change in our creditworthiness, Chipeta may sell our natural gas and apply amounts received against any amounts we owe to Chipeta, set off any amount owed to us against amounts owed to Chipeta or cease processing our natural gas until our account is current, with interest. Chipeta may also demand adequate assurance of performance from us, which may be in the form of a standby irrevocable letter of credit, prepayment or performance bond or guaranty.
Pursuant to the Amended and Restated Monarch Agreement, Monarch agreed, among other things, to release and waive its existing right to process the first 50,000 MMBtu/day of our gas delivered to Monarch’s gathering system, referred to as the Excluded Production, and retain all processing rights for all gas volumes produced from certain of our reserves in excess of the Excluded Production. The Excluded Production may be reduced if we fail to meet certain drilling investment targets, after three years from the beginning of primary term of the Chipeta Processing Agreement, which was February 7, 2013. More specifically, we are required to commit or cause to be committed $50 million for drilling and completing new wells by February 2016, or else the Excluded Production may be reduced by an amount up to 20,000 MMBtu/day. The Amended and Restated Monarch Agreement also provides that we are committed to deliver to Monarch for gathering a minimum of 25,000 Mcf/day and we are obligated to pay for any shortfall following the end of each quarterly period, measured by the shortfall quantity for the quarter multiplied by the then-current gathering and processing fees under the agreement.
In connection with the Amended and Restated Monarch Agreement, we also entered in to the QPC Transportation Agreement, pursuant to which we agreed to enter into separate transportation services agreements for firm transportation services. We are committed to deliver to QPC for transportation services a minimum of 25,000 MMbtu/day.
Since the beginning of the primary term of the Chipeta Gas Processing Agreement, Chipeta has provided all of our natural gas processing services, and we have not produced any amounts of natural gas in excess of the Excluded Production. Monarch and QPC continue to gather and transport our natural gas.
There is substantial doubt regarding our ability to generate sufficient cash flows from operations to fund our ongoing operations. The maximum undiscounted deficiency payments under the Chipeta Gas Processing Agreement, the Amended and Restated Monarch Agreement and the QPC Transportation Agreement, over the full terms of these contracts, are estimated to be approximately $59 million. Of this amount, approximately $40 million would be owed to Chipeta, $8.5 million would be owed to Monarch and $12.5 million would be owed to QPC. These amounts are owed regardless of whether we deliver any natural gas quantities to the applicable parties. If we are unable to fund additional drilling projects, and based on our December 31, 2012 reserve estimates, assuming no future drilling and constant gas prices, we estimate that we could have a reasonably possible minimum production shortfall of approximately 54,000 MMcf valued at approximately $37 million in aggregate deficiency payment obligations on an undiscounted gross basis.
We are considering several alternatives to mitigate the reasonably possible estimated production shortfall such as the sale of our firm commitment positions, seeking relief from the firm commitments because of the permitting delays in the area and the purchase of production quantities to meet our minimum production requirements. Also, future increases in gas prices would increase the related reserve estimates and reduce possible shortfalls. However, there is no assurance we will be successful in accomplishing these actions should there be a deficiency. Accordingly, we have not accrued any amounts as of December 31, 2012 as it is not probable or reasonably estimable. Please read “Item 1A.-Risk Factors-Pursuant to the Gas Processing Agreement with Chipeta and the Amended and Restated Monarch
Agreement, we may be required to make periodic deficiency payments for any shortfalls from the specified minimum volume commitments.”
Please read “Item 1.-Business-2012 and Recent Highlights-Gas Processing Agreements” above for more information.
Office Space
We lease approximately 11,170 square feet of office space in Denver, Colorado. The average annual rent expense over the term of the lease is approximately $216,000 and the lease terminates on May 31, 2017.
ITEM 3
ITEM 3 - LEGAL PROCEEDINGS
Clean Water Act Compliance Order Matter
On October 3, 2011, we received a compliance order from the EPA Region 8 under the authority of the federal Clean Water Act. The compliance order alleges that we violated the Clean Water Act by discharging fill material into wetlands adjacent to the Green River in Utah without authorization on two occasions: (i) once when we constructed an access road to a future well location in either 2004 or 2005 and (ii) once when we constructed an access road and a well pad in 2007 or 2008. The compliance order directs us to remove all dredged or fill material alleged to have been placed in the wetlands and to restore the wetlands to their pre-impact condition and grade, which would require us to plug and abandon the well alleged to have been installed in a wetlands area. The compliance order does not seek any civil penalties for the alleged violations. We disagree with some of the factual contentions in the compliance order, and we have had a number of discussions with the EPA concerning the order. However, we have been unable to negotiate a successful resolution of the alleged violations with the EPA, and as a result, we filed a lawsuit in federal district court in the District of Colorado on June 25, 2012. The lawsuit seeks judicial review of the compliance order, specifically review of the EPA’s contention that the affected areas are wetlands, or if they are wetlands, whether they are wetlands that are subject to federal regulatory jurisdiction under the Clean Water Act. On September 5, 2012, the EPA, represented by the Department of Justice, answered, and the United States separately counterclaimed for an injunction seeking substantially the same relief that the EPA seeks in the compliance order but also requesting civil penalties for each day of alleged discharges of fill material and each day of alleged violation of the compliance order. We have answered the EPA’s counterclaim. In late January 2013, pursuant to a Scheduling Order before the court, we submitted a brief in support of our claims under the original suit filed in June 2012. We are not able to predict the outcome of this matter at this time.
NEPA Suit
In June 2012, the BLM signed and issued a Rule of Decision on the EIS that authorizes the development of our Uinta Basin field upon federal lands in Duchesne and Uintah Counties, Utah. This field includes our core Riverbend Project. However on January 18, 2013, certain non-governmental environmental organizations, including the Southern Utah Wilderness Alliance, or SUWA, filed a suit against the BLM, challenging the ROD issued by that agency. In its complaint, SUWA alleges that the BLM failed to comply with the requirements of NEPA and its implementing regulations. SUWA was seeking, among other things, that the ROD and EIS be set aside, the effect of which would void the BLM’s authorization for us to proceed with its planned project. Only recently, on February 13, 2013, SUWA voluntarily submitted notice of dismissal of the suit to the District Court. Because SUWA voluntarily withdrew its suit, it has the opportunity to refile the suit at a later date. Whether SUWA will refile this suit at a later date is currently unknown to us. While any future suit by SUWA or any other third party that seeks to set aside the ROD issued by the BLM for our planned project in the Uinta Basin field in Utah could, if
successful, have a material adverse effect on our ability to perform the planned project, we would not expect the outcome of such proceeding to have a material adverse effect on the Company’s financial position, results of operations or cash flows.
Hat Creek Settlement
In February 2013, we settled a claim with one of our working interest owners, Hat Creek Energy LLC (“Hat Creek”), in connection with a well that was operated by us and owned by both parties. Hat Creek filed the claim on April 2, 2012 in the Denver District Court, alleging that Hat Creek did not consent to certain reworking operations performed by us in violation of the joint operating agreement, and that Hat Creek’s working interest in the well was impaired as a result. Hat Creek sought damages of not less than $200,000, and we sought counterclaim damages for receivables owed by Hat Creek and for the reworking costs. We settled this claim for $315,000 consisting of a $160,000 cash payment to Hat Creek and the forgiveness of $155,000 in accounts receivable owed to us by Hat Creek. In addition, the settlement provides that we will receive Hat Creek’s ownership interest in the well. The final settlement has been accrued in the accompanying consolidated financial statements and is dependent upon the completion of the final settlement documents.
ITEM 4
ITEM 4 - MINE SAFETY DISCLOSURES
Not applicable.
PART II
ITEM 5
ITEM 5 - MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Market Information
The Company’s common stock is currently traded on the Exchange under the symbol “GSX.” As of March 6, 2013, the Company had 164 record shareholders of its common stock.
The following table sets forth, for the periods indicated, the high and low sales prices per share of the Company’s common stock as reported on the Exchange for the periods reflected.
Dividends
We have never declared or paid cash dividends on our common stock. Our management anticipates that we will retain future earnings, if any, to satisfy our operational and other cash needs and does not anticipate that dividends will be paid on our common stock in the foreseeable future. Furthermore, our 2015 Notes contain covenants that restrict the payment of dividends. See further discussion in Note 5 - Senior Convertible Notes of the accompanying financial statements.
ITEM 6
ITEM 6 - SELECTED FINANCIAL DATA
The following table sets forth selected financial data derived from our historical consolidated financial statements and related notes regarding our financial position and results of operations as the dates indicated. Certain reclassifications have been made to prior financial data to conform to the current presentation. The financial information is an integral part of, and should be read in conjunction with, the consolidated financial statements and notes thereto included in Item 8 hereof. Information concerning significant trends in financial condition and results of operations is contained in “Item 7.
ITEM 7 - MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion should be read in conjunction with our historical consolidated financial statements and notes, as well as the selected historical consolidated financial data included elsewhere in this report.
Forward-Looking Statements
Please refer to the section entitled “Cautionary Statement Regarding Forward-Looking Statements” and “Item 1A.-Risk Factors,” for a discussion of factors which could affect the outcome of forward-looking statements used in this report.
Overview
We are a natural gas and petroleum exploitation, development and production company engaged in locating and developing hydrocarbon prospects, primarily in the Rocky Mountain region. Our business strategy is to enhance shareholder value by generating and developing high-potential exploitation resources in this area. Our principal business is the acquisition of leasehold interests in petroleum and natural gas rights, either directly or indirectly, and the exploitation and development of properties subject to those leases. We are currently focusing our operational efforts in the Riverbend Project located in the Uinta Basin of northeastern Utah, targeting the Green River, Wasatch, Mesaverde, Blackhawk, Mancos, Dakota and Morrison formations.
Due to the significant extended decline in the natural gas market and in sustained low natural gas prices caused by excess production and stagnant growth in the demand for natural gas, we have not been able to recover our exploration and development costs as anticipated. As such, there is substantial doubt
regarding our ability to generate sufficient cash flows from operations to fund our ongoing operations, and we currently anticipate that cash on hand and forecasted cash flows from operations will only be sufficient to fund cash requirements for working capital, including debt payment obligations, through the second quarter of 2013. Our prior revolving credit facility matured in June 2012, at which time we repaid all of the outstanding borrowings thereunder. While we have attempted to secure a replacement facility, we have been unable to do so on acceptable terms and we are no longer actively in discussions to obtain a replacement facility. There can be no assurance that we will be able to adequately finance our operations or execute our existing short-term and long-term business plans, and our liquidity and results of operations are likely to be materially adversely affected if we are unable to generate sufficient operating cash flows, secure additional capital or otherwise pursue a strategic restructuring, refinancing or other transaction to provide us with additional liquidity. We have engaged a financial advisor to assist us in evaluating such potential strategic alternatives. It is possible these strategic alternatives will require us to make a pre-package, pre-arranged or other type of filing for protection under Chapter 11 of the U.S. Bankruptcy Code (or an involuntary petition for bankruptcy may be filed against us). As a result of these factors, there is substantial doubt about our ability to continue as a going concern. For additional information regarding our current liquidity situation, please see “Liquidity and Capital Resources” below.
See “2012 and Recent Highlights” in “Item 1 - Business”
2013 Capital Budget
We have not allocated any amounts to the 2013 capital budget. As discussed above, due to the significant extended decline in the natural gas market and sustained low natural gas prices caused by excess production and stagnant growth in the demand for natural gas, we have not been able to recover our exploration and development costs as anticipated. There is substantial doubt regarding our ability to generate sufficient cash flows from operations to fund our ongoing operations, and we currently anticipate that cash on hand and forecasted cash flows from operations will only be sufficient to fund cash requirements for working capital, including debt payment obligations, through the second quarter of 2013. This expectation is based on various assumptions, including those related to future natural gas and oil prices, production results and the effectiveness of our cash management strategy discussed below, some or all of which may not prove to be correct and may result in our inability to meet cash requirements prior to the second quarter of 2013. See “Liquidity and Capital Resources.”
Summary of Capital Expenditures
The following table summarizes our capital expenditures during 2012 by reconciling the cash paid for acquisitions, development and exploration included within the Consolidated Statement of Cash Flows in Item 8.
Production and Reserve Information
The following tables present certain of our production information for each of the three years ended December 31, 2012 and our estimated proved reserves as of December 31 of each year presented. The Mcfe calculations assume a conversion of 6 Mcf for each Bbl of oil. The decrease in oil and gas production and reserve quantities during 2012 reflects the conveyance of a 50% interest in certain of our Uinta Basin properties to our joint venture partner as part of the Uinta Basin Transaction which closed on March 22, 2012.
Our natural gas production decreased by approximately 34% during 2012 as compared with 2011 and by approximately 11% during 2011 as compared with 2010. The production decrease during 2012 is primarily due to the Uinta Basin Transaction as well as normal production declines and the decrease in 2011 is the result of fewer completions of up-hole zones during 2011, third-party gathering system throughput issues and normal production declines.
Our proved reserve quantities decreased by approximately 65% and 6% during the years ended December 31, 2012 and 2011, respectively, primarily due to the Uinta Basin Transaction in 2012, revisions of previous estimates resulting from well performance on certain of our wells and production declines during both years that were not offset by the extensions and discoveries in each year. The revisions of reserve estimates during 2011 were primarily due to better than anticipated well performance related to behind pipe reserves that began producing during the year.
Liquidity and Capital Resources
General
We have historically generated cash from operations from the sale of oil and natural gas with the exception of the years ended December 31, 2012 and 2011, and have relied in the past primarily on the issuance of equity, borrowings under our prior revolving credit facility and farm-out and other similar types of transactions to fund working capital and the acquisition of our prospects and leases. For the year ended December 31, 2012, we incurred a net loss of $22,232,391 and had negative cash flow from operations of $3,668,672. As of December 31, 2012, we had an accumulated deficit of $244,808,156.
Our consolidated financial statements included in this Annual Report have been prepared assuming that we will continue as a going concern, which contemplates realization of assets and the satisfaction of liabilities in the normal course of business for the next twelve months. However, due to the significant
extended decline in the natural gas market and sustained low natural gas prices caused by excess production and stagnant growth in the demand for natural gas, we have not been able to recover our exploration and development costs as anticipated. For example, we had net losses and negative cash flow from operations for the three and twelve months ended December 31, 2012 and at December 31, 2012 had an accumulated deficit of $244,808,156. There is substantial doubt regarding our ability to generate sufficient cash flows from operations to fund our ongoing operations, and we currently anticipate that cash on hand and forecasted cash flows from operations will only be sufficient to fund cash requirements for working capital, including debt payment obligations, through the second quarter of 2013. This expectation is based on various assumptions, including those related to future natural gas and oil prices, production results and the effectiveness of our cash management strategy discussed below, some or all of which may not prove to be correct and may result in our inability to meet cash requirements prior to the second quarter of 2013. Our prior revolving credit facility matured in June 2012, at which time we repaid all of the outstanding borrowings thereunder. While we have attempted to secure a replacement facility, as of the date of this Annual Report, we have been unable to do so on acceptable terms and are no longer actively in discussions to obtain a replacement facility. Furthermore, we may not achieve profitability from operations in the near future or at all and we may continue to experience significant losses. As a result of these factors, there is substantial doubt about our ability to continue as a going concern.
As of December 31, 2012, we had $45,168,000 aggregate principal amount of our 2015 Notes outstanding. The 2015 Notes bear interest at a rate of 5.50% per annum, payable in cash semi-annually in arrears on April 5th and October 5th of each year. Our failure to make an interest payment on the 2015 Notes, if not cured within 30 days, would result in a default under the indenture governing the 2015 Notes, which would permit the holders of the 2015 Notes to accelerate repayment of the 2015 Notes.
In addition, the delisting of our common stock from the Exchange may also result in a default under the Indenture. We have received notices from the Exchange notifying us that we do not satisfy the Exchange’s continued listing standards. We submitted a Plan of compliance to the Exchange on February 11, 2013. Pursuant to the Plan, we intend to lower costs, rationalize assets, refocus our development program toward oil and liquids, especially in the Green River Formation, and continue our California program with the potential goal of expanding our California model. The Plan also considers strategic alternatives, including the debt restructuring and sales of assets, if necessary. However, there can be no assurance that this Plan will be accepted by the Exchange or that we will be able to achieve compliance with the Exchange’s continued listing standards within the required time frame. If the Plan is not accepted, we will be subject to delisting proceedings. Furthermore, if the Plan is accepted but we are not in compliance with the continued listing standards of the Company Guide by June 30, 2013, or if we do not make progress consistent with the Plan, the Exchange staff will initiate delisting proceedings as it deems appropriate. Please read “Item 1 - Business-2012 and Recent Highlights- NYSE MKT LLC Communications” for more information.
Pursuant to our JOA and contract operating agreements in connection with the Uinta Basin Transaction pursuant to which we serve as operator, if we become insolvent, bankrupt or are placed into receivership, we will be deemed to have resigned as operator or the other party may have termination rights. We also have commitments under our gas processing and transportation contracts as discussed in “Delivery Commitments” in “Item 2 - Properties.” We may be required to make periodic deficiency payments for any shortfalls from the specified minimum volume commitments. Please read “Item 1A.-Risk Factors-Pursuant to the Gas Processing Agreement with Chipeta and the Amended and Restated Monarch Agreement, we may be required to make periodic deficiency payments for any shortfalls from the specified minimum volume commitments.”
Failure to generate operating cash flow or to obtain additional financing for the development of our properties could result in substantial dilution of our property interests or delay or cause indefinite
postponement of further exploration and development of our prospects resulting in the possible loss of our properties. This has caused us to alter our business plans, and we may be further required to reduce our exploration and development plans. For example, we have not allocated any amounts to the 2013 capital budget. In particular, we face uncertainties relating to our ability to fund the level of capital expenditures required for oil and gas exploration and production activities. We intend to fund our anticipated cash requirements through the second quarter of 2013 primarily through cash on hand and cash flows from operations, although we cannot assure you that cash on hand and cash flows from operations will be sufficient to fund such requirements. If they are not, our ability to continue as a going concern as well as to fund our operating budget will be significantly limited, and our liquidity and results of operations will be materially adversely affected.
To continue as a going concern, we must generate sufficient operating cash flows, secure additional capital or otherwise pursue a strategic restructuring, refinancing or other transaction to provide us with additional liquidity. The urgency of our liquidity situation may require us to pursue such a transaction at an inopportune time. Moreover, our ability to successfully implement, and the cost of, any such transaction will depend on numerous factors, including:
· demand and prices for natural gas and oil;
· general economic conditions;
· strength of the credit and capital markets;
· our ability to successfully execute our operational strategies, and our operating and financial performance;
· our ability to remain in compliance with our debt and equity instruments;
· our stock price, and ability to regain and maintain compliance with the Exchange’s continued listing requirements;
· our ability to remain in compliance with our operational agreements, including our gas processing, gathering and transportation agreements;
· our counterparties refraining from exercising any remedies available as a result of the determination that we are insolvent or unable to perform in accordance with the contract;
· our ability to maintain relationships with our suppliers, customers, employees, stockholders and other third parties; and
· market uncertainty in connection with our ability to continue as a going concern as well as investor confidence in us.
If we fail to generate sufficient operating cash flows, secure additional capital or otherwise restructure or refinance our business before the end of the second quarter, we will not have adequate liquidity to fund our operations and meet our obligations (including our debt payment obligations), will not be able to continue as a going concern, and could potentially be forced to seek relief through a filing under Chapter 11 of the U.S. Bankruptcy Code (or an involuntary petition for bankruptcy may be filed against us).
A bankruptcy filing by or against us would subject our business and operations to various risks, including but not limited to, the following:
· a bankruptcy filing by or against us may adversely affect our business prospects, including our ability to continue to obtain and maintain the contracts necessary to operate our business on competitive terms;
· a bankruptcy filing by or against us may cause an event of default under the indenture governing the 2015 Notes;
· certain provisions in our operating agreements may be triggered such that we would be deemed to have resigned as operator or the agreements may be terminated by the other party;
· we may be unable to retain and motivate key executives and employees through the process of reorganization, and we may have difficulty attracting new employees;
· there can be no assurance as to our ability to maintain or obtain sufficient financing sources for operations or to fund any reorganization plan and meet future obligations;
· there can be no assurance that we will be able to successfully develop, prosecute, confirm and consummate one or more plans of reorganization that are acceptable to the bankruptcy court and our creditors, equity holders and other parties in interest; and
· the value of our common stock could be reduced to zero as result of a bankruptcy filing.
In order to address our liquidity constraints and in addition to our ongoing efforts to secure additional capital or otherwise pursue a strategic restructuring, refinancing or other transaction to provide us with additional liquidity, we have embarked on a cash management strategy to enhance and preserve as much liquidity as possible. This plan contemplates us, among other things:
· reducing expenditures by eliminating, delaying or curtailing discretionary and non-essential spending, and not designating any capital budget for 2013;
· managing working capital;
· delaying certain drilling projects;
· pursuing farm-out and other similar types of transactions to fund working capital needs;
· evaluating our options for the divestiture of certain assets;
· considering asset purchases through the issuance of equity;
· investigating merger opportunities; and
· restructuring and reengineering our organization and processes to reduce operating costs and increase efficiency.
We cannot provide any assurances that we will be successful in accomplishing any of these plans or that any of these actions can be effected on a timely basis, on satisfactory terms or maintained once initiated. Furthermore, our cash management strategy, if successful, may limit certain of our operational and strategic initiatives designed to grow our business over the long term.
Uinta Basin Transaction
On March 22, 2012, we closed the Uinta Basin Transaction, pursuant to which we (i) sold to Wapiti an undivided 50% interest in certain of our Uinta Basin producing oil and gas assets for $18.0 million in cash and $1.19 million in the form of a promissory note receivable from Wapiti (which was paid in full during the second quarter of 2012) and (ii) transferred to Wapiti an undivided 50% of our interest in our Uinta Basin non-producing oil and gas assets in exchange for, among other agreements, Wapiti’s commitment to fund $30.0 million of the drilling and completion costs associated with the exploration and development of the subject assets.
Of Wapiti’s $30.0 million funding commitment, $15.0 million will be paid on our behalf, and we have agreed to provide an additional $7.5 million of drilling and completion costs. Accordingly, the total program will be $37.5 million. If we are not able to pay our share of the above costs, we may lose certain rights granted under the Development Agreement and related operating agreements, including the right to continue as operator or contract operator of the properties, the right to make proposals or elect to participate in operations under the Development Agreement or any operating agreement, the right to call,
attend and vote at meetings of the operating committee, the right to transfer our interest in the properties and the joint venture, the right to acquire Wapiti’s interest in the properties under the right of first offer provisions of the Development Agreement and the right to acquire its pro rata share of additional properties acquired by Wapiti within the area of mutual interest identified in the Development Agreement. We have not incurred any costs to date and there is substantial doubt regarding our ability to fund our share of the drilling and completion costs. We have not incurred any costs to date and there is substantial doubt regarding our ability to fund our share of the drilling and completion costs.
We used approximately $10.5 million of the proceeds from the Uinta Basin Transaction to repay outstanding borrowings under our prior revolving credit facility. We expected to use the remaining proceeds for our capital expenditures consisting of approximately $5.0 million for additional investment in existing and new California oil and gas prospects in the San Joaquin Basin as well as for working capital, acquisitions of oil and natural gas properties and other general corporate purposes. However, due to low natural gas prices and permitting delays, we did not drill any natural gas wells in Utah during the remainder of 2012.
Sources and Uses of Cash
The following table summarizes our sources and uses of cash for each of the three years ended December 31, 2012, 2011 and 2010.
Cash provided by operations decreased by $3,239,172 during 2012 as compared with 2011 primarily due the decrease in oil and gas revenue resulting from the sale of approximately 50% of the working interest in certain of our properties. The decrease of $4,073,351 in cash provided by operations from 2010 to 2011 was primarily due to approximately $2,163,000 of workover expenses incurred in 2011 and a decrease in oil and gas revenue resulting from the production decline discussed previously.
Our investing activities during the three years ended December 31, 2012 related primarily to our development and exploration activities, fixed asset additions and changes in advances from joint interest owners. The activity during 2012 included the sales proceeds from the Uinta Basin Transaction and the activity during 2010 included proceeds of $24,309,000 associated primarily with the sale of our gathering and evaporative facilities and the sale of a partial working interest in 32 producing wells.
During the three years ended December 31, 2012, our financing activity included borrowings and repayments under our credit facility. The 2011 activity also included $8,713,053 in net proceeds from the issuance of common stock and warrants and the $400,000 for the repayment of certain convertible notes. The 2010 activity included the $54,400 repurchase of certain convertible notes and the payment of a deposit for $500,000.
Schedule of Contractual Obligations
The following table summarizes the Company’s obligations and commitments to make future payments under its notes payable, operating leases, employment contracts, consulting agreements and service contracts for the periods specified as of December 31, 2012.
(a) These values represent the gross commitments to deliver fixed and determinable quantities of natural gas per our gathering, transportation and processing agreement with Monarch, QPC and Chipeta over the life of the contracts. These amounts are owed regardless of whether we deliver any natural gas quantities to the applicable parties. For more information, see “Item 2. - Properties - Delivery Commitments.”
(b) The accuracy and timing of the asset retirement obligations cannot be precisely determined in advance. See further discussion in Note 3 - Significant Accounting Policies-Asset Retirement Obligation of the accompanying consolidated financial statements.
Forward Sales Contracts
During March 2010, pursuant to the Base Contract for Sale and Purchase of Natural Gas with Anadarko Energy Services Company, dated December 1, 2007, we entered into a term sales and transportation transaction to sell up to 50,000 MMBtu per day of our gross production through 2013 from the Uinta Basin. The transaction contains two pricing mechanisms: (1) up to 25,000 MMBtu per day will be priced at the NW Rockies first of month price and (2) up to 25,000 MMBtu per day will be priced at the first of the month index price as published by Gas Daily for the North West Wyoming Poll Index price. We account for our agreement to physically settle our production as an executory contract. We do not believe that the loss of this contract would materially affect our business because there are other potential purchasers in the areas in which we sell our production; however, we may not be able to find other purchasers who would purchase our production on terms comparable to our current arrangements.
Derivatives
Our results of operations and operating cash flows are affected by changes in market prices for oil and natural gas. From time to time, we use commodity derivative instruments to provide a measure of stability to our cash flows in an environment of volatile oil and gas prices and to manage our exposure to commodity price risk. As of December 31, 2011, natural gas derivative instruments consisted of one costless collar agreement for production from January 1, 2012 through December 31, 2012. During June
2012, we monetized this contract for net proceeds of $677,868. See further discussion in “Item 7A
ITEM 7A - QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
We are exposed to a variety of market risks, including commodity price risk. We address these risks through a program of risk management which may include the use of derivative instruments. The following quantitative and qualitative information is provided about financial instruments to which we were a party at December 31, 2012, and from which we may incur future gains or losses from changes in commodity prices or market interest rates. We do not enter into derivative or other financial instruments for speculative or trading purposes.
Hypothetical changes in the price of our common stock and volatility rates chosen for the following estimated sensitivity analyses are considered to be reasonably possible near-term changes generally based on consideration of past fluctuations for each risk category. However, since it is not possible to accurately predict future changes in in the price of our common stock and volatility rates, these hypothetical changes may not necessarily be an indicator of probable future fluctuations.
Further, our cash equivalents are exposed to concentrations of credit risk. We manage and control this risk by placing these funds with major financial institutions with high credit ratings. Our receivables are comprised of oil and gas revenue receivables and joint interest billings receivable, which amounts are due from a limited number of entities. Therefore, collectability is dependent upon the general economic conditions of the few purchasers and joint interest owners. The receivables are not collateralized; however, to date, we have had minimal bad debts.
Warrant Derivative Risk
On June 15, 2011, we issued warrants to purchase 18,750,000 shares of common stock and on August 3, 2011, we issued warrants to purchase 11,500,000 shares of common stock, collectively referred to as the Warrants. The Warrants have an initial exercise price of $0.35 per share (subject to adjustment) with a sixty-month term, as further described in Note 3 - Significant Accounting Policies of the accompanying consolidated financial statements. The Warrants contain a contingent cash settlement provision at the option of the holder and accordingly, are classified as a derivative liability and are subject to the classification and measurement standards for derivative financial instruments. Estimating fair values of derivative financial instruments requires the development of significant and subjective estimates that may, and are likely to, change over the duration of the instrument with related changes in internal and external market factors. In addition, option-based techniques are highly volatile and sensitive to changes in the trading price of our common stock, which has a high-historical volatility. With all other factors remaining constant as of December 31, 2012:
(i) the warrant derivative liability would remain unchanged if the trading price of our common stock was reduced to zero and would increase by approximately $1.9 million for a $0.10 per share increase in the trading price of our common stock; and
(ii) the warrant derivative liability would remain unchanged for a 10% increase in the volatility rate and would decrease by approximately $302,500 for a 10% decrease in the volatility rate.
Commodity Price Risk
During June 2012, we monetized our remaining commodity derivative for $677,868 and do not have any commodity derivative contracts outstanding as of December 31, 2012.
ITEM 8
ITEM 8 - FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Report of Independent Registered Public Accounting Firm
Consolidated Balance Sheets at December 31, 2012 and 2011
82-83
Consolidated Statements of Operations for the Years Ended December 31, 2012, 2011 and 2010
Consolidated Statements of Stockholders’ Equity for the Years Ended December 31, 2012, 2011 and 2010
Consolidated Statements of Cash Flows for the Years Ended December 31, 2012, 2011 and 2010
Notes to Consolidated Financial Statements
Report of Independent Registered Public Accounting Firm
The Board of Directors and Stockholders
Gasco Energy, Inc.:
We have audited the accompanying consolidated balance sheets of Gasco Energy, Inc. and subsidiaries (the Company) as of December 31, 2012 and 2011, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2012. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2012 and 2011, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2012, in conformity with U.S. generally accepted accounting principles.
The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in note 2 to the consolidated financial statements, the Company has suffered recurring losses and negative cash flows from operations that raise 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 consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 6, 2013 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.
/s/ KPMG LLP
Denver, Colorado
March 6, 2013
GASCO ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
The accompanying notes are an integral part of the consolidated financial statements.
GASCO ENERGY, INC.
CONSOLIDATED BALANCE SHEETS (continued)
The accompanying notes are an integral part of the consolidated financial statements.
GASCO ENERGY, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
The accompanying notes are an integral part of the consolidated financial statements.
GASCO ENERGY, INC.
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
The accompanying notes are an integral part of the consolidated financial statements.
GASCO ENERGY, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
The accompanying notes are an integral part of the consolidated financial statements.
GASCO ENERGY INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEARS ENDED DECEMBER 31, 2012, 2011 AND 2010
NOTE 1 - ORGANIZATION
Gasco Energy, Inc. (“Gasco,” the “Company,” “we,” “our” or “us”) was incorporated under the laws of the State of Nevada on April 21, 1997. Gasco is a natural gas and petroleum exploitation, development and production company engaged in locating and developing hydrocarbon resources, primarily in the Rocky Mountain region. The Company’s principal business strategy is to enhance stockholder value by generating and developing high-potential exploitation resources in these areas. The Company’s principal business is the acquisition of leasehold interests in petroleum and natural gas rights, either directly or indirectly, and the exploitation and development of properties subject to these leases. The Company is currently focusing its operational efforts in the Riverbend Project located in the Uinta Basin of northeastern Utah, targeting the Green River, Wasatch, Mesaverde, Blackhawk, Mancos, Dakota and Morrison formations.
NOTE 2 - GOING CONCERN
The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern, which contemplates realization of assets and the satisfaction of liabilities in the normal course of business for the twelve-month period following the date of these consolidated financial statements. However, due to the extended decline in the natural gas market and sustained low natural gas prices caused by excess production and stagnant growth in the demand for natural gas, the Company has not been able to recover its exploration and development costs as anticipated. There is substantial doubt regarding the Company’s ability to generate sufficient cash flows from operations to fund its ongoing operations, and the Company currently anticipates that cash on hand and forecasted cash flows from operations will only be sufficient to fund cash requirements for working capital, including debt payment obligations, through the second quarter of 2013. This expectation is based on various assumptions, including those related to future natural gas and oil prices, production results and the effectiveness of the Company’s cash management strategy discussed below, some or all of which may not prove to be correct and may result in the Company’s inability to meet cash requirements prior to the second quarter of 2013. As a result of these factors, there is substantial doubt about the Company’s ability to continue as a going concern.
The Company received notices from the NYSE MKT LLC (the “Exchange”) notifying it that it does not satisfy the continued listing standards set forth in the Exchange’s Company Guide. On December 6, 2012, we received a notice from the Exchange indicating that we do not satisfy the continued listing standards of the Exchange set forth in Section 1003(f)(v) of the Company Guide because our common stock has traded at a low price per share for a substantial period of time. In the notice, the Exchange predicated our continued listing on the Exchange on us effecting a reverse stock split of our common stock by June 6, 2013. On January 11, 2013, we received a notice from the Exchange indicating that we do not satisfy the continued listing standards of the Exchange set forth in Section 1003(a)(iv) of the Company Guide, which applies if a listed company has sustained losses which are so substantial in relation to its overall operations or its existing financial resources, or its financial condition has become so impaired that it appears questionable, in the opinion of the Exchange, as to whether such company will be able to continue operations and/or meet its obligations as they mature. The Company submitted a plan of compliance (a “Plan”) to the Exchange on February 11, 2013, however, there can be no assurance that the Plan will be accepted by the Exchange or that the Company will be able to achieve compliance with the Exchange’s continued listing standards within the required time frame. Pursuant to the Plan, the Company intends to lower costs, rationalize assets, refocus our development program toward oil and liquids,
especially in the Green River Formation, and continue the California program with the potential goal of expanding the California model. The Plan also considers strategic alternatives, including the debt restructuring and sales of assets, if necessary. If the Plan is not accepted, the Company will be subject to delisting proceedings.
Furthermore, if the Plan is accepted but the Company is not in compliance with the continued listing standards of the Company Guide by June 30, 2013, or if the Company does not make progress consistent with the Plan, the Exchange staff will initiate delisting proceedings as it deems appropriate.
The Company’s prior revolving credit facility matured on June 29, 2012, and as of the date of this Annual Report, the Company has been unable to obtain a replacement facility on acceptable terms and is no longer actively in discussions to obtain a replacement facility. Furthermore, the Company may not achieve profitability from operations in the near future or at all. The Company had net losses and negative cash flow from operations for the year ended December 31, 2012 and at December 31, 2012 had an accumulated deficit of $244,808,156.
As of December 31, 2012, the Company had $45,168,000 aggregate principal amount of its 5.5% Convertible Senior Notes due 2015 (the “2015 Notes”) outstanding. The 2015 Notes bear interest at a rate of 5.50% per annum, payable in cash semi-annually in arrears on April 5th and October 5th of each year. The Company’s failure to make an interest payment on the 2015 Notes, if not cured within 30 days, would result in a default under the indenture governing the 2015 Notes, which would permit the holders of the 2015 Notes to accelerate repayment of the 2015 Notes. In addition, if the Company’s stock was delisted, it could result in a default under the Indenture.
The Company also has commitments under its gas transportation and processing agreements as discussed further in Note 16 - Commitments, herein.
Failure to generate operating cash flow or to obtain additional financing for the development of the Company’s properties could result in substantial dilution of our property interests or delay or cause indefinite postponement of further exploration and development of our prospects resulting in the possible loss of its properties. This could cause the Company to alter its business plans, including further reducing its exploration and development plans. In particular, the Company faces uncertainties relating to its ability to fund the level of capital expenditures required for oil and gas exploration and production activities. The Company intends to fund its anticipated cash requirements through the second quarter of 2013 primarily through cash on hand and cash flows from operations, although the Company cannot provide assurances that cash on hand and cash flows from operations will be sufficient to fund such requirements. If they are not, the Company’s ability to execute its growth plans as well as to fund its operating budget will be significantly limited, and its liquidity and results of operations may be materially adversely affected.
To continue as a going concern, the Company must generate sufficient operating cash flows, secure additional capital or otherwise pursue a strategic restructuring, refinancing or other transaction to provide it with additional liquidity. The Company has engaged a financial advisor to assist it in evaluating such potential strategic alternatives. It is possible these strategic alternatives will require the Company to make a pre-package, pre-arranged or other type of filing for protection under Chapter 11 of the U.S. Bankruptcy Code (or an involuntary petition for bankruptcy may be filed against the Company). The Company’s ability to do so will depend on numerous factors, some of which are beyond its control. If the Company is unable to generate sufficient operating cash flows, secure additional capital or otherwise restructure or refinance the business before the end of the second quarter of 2013, it will not have adequate liquidity to fund its operations and meet its obligations (including its debt payment obligations), the Company will not be able to continue as a going concern, and could potentially be forced to seek relief through a filing under Chapter 11 of the U.S. Bankruptcy Code (or an involuntary petition for bankruptcy may be filed
against it). The accompanying consolidated financial statements do not include any adjustments relating to the recoverability and classification of assets, carrying amounts, or the amount and classification of liabilities that may result, should the Company be unable to continue as a going concern.
In order to address the Company’s liquidity constraints and in addition to its ongoing efforts to secure additional capital or otherwise pursue a strategic restructuring, refinancing or other transaction to provide it with additional liquidity, the Company has embarked on a cash management strategy to enhance and preserve as much liquidity as possible. This plan contemplates the Company, among other things:
· reducing expenditures by eliminating, delaying or curtailing discretionary and non-essential spending, and not designating any capital budget for 2013;
· managing working capital;
· delaying certain drilling projects;
· pursuing farm-out and other similar types of transactions to fund working capital needs;
· evaluating its options for the divestiture of certain assets;
· considering asset purchases through the issuance of equity;
· investigating merger opportunities; and
· restructuring and reengineering the Company’s organization and processes to reduce operating costs and increase efficiency.
The Company cannot provide any assurances that it will be successful in accomplishing any of these plans or that any of these actions can be effected on a timely basis, on satisfactory terms or maintained once initiated. Furthermore, the Company’s cash management strategy, if successful, may limit certain of its operational and strategic initiatives designed to grow its business over the long term.
NOTE 3 - SIGNIFICANT ACCOUNTING POLICIES
Basis of Presentation
The accompanying consolidated financial statements include Gasco and its wholly-owned subsidiaries. All significant intercompany transactions have been eliminated.
Cash and Cash Equivalents
All highly liquid investments purchased with an original maturity of three months or less at the time of acquisition are considered to be cash equivalents.
Concentration of Credit Risk
The Company’s cash equivalents and derivative instruments are exposed to concentrations of credit risk. The Company manages and controls this risk by placing these funds and contracts with major financial institutions with high credit ratings.
The Company’s receivables are comprised of oil and gas revenue receivables and joint interest billings receivable. The amounts are due from a limited number of entities. Therefore, the collectability is dependent upon the general economic conditions of the few purchasers and joint interest owners. The receivables are not collateralized. However, to date the Company has had minimal bad debts.
Significant Customers
During the years ended December 31, 2012, 2011 and 2010 70%, 78% and 83%, respectively, of the Company’s production was sold to Anadarko Petroleum Corporation; during 2012, 2011 and 2010, 24%, 16% and 13% of the Company’s production was sold to EnWest Marketing LLC. Approximately 80% of the accounts receivable - revenue as of December 31, 2012 are due from Anadarko Petroleum Corporation. However, Gasco does not believe that the loss of a single purchaser, including Anadarko Petroleum Corporation, would materially affect the Company’s business because there are numerous other purchasers in the areas in which Gasco sells its production. However, the Company may not be able to find other purchasers who would purchase its production on terms comparable to its current arrangements.
Inventory
Inventory consists of pipe and tubular goods intended to be used in the Company’s oil and gas operations, and is stated at the lower of cost or market using the average cost valuation method.
Oil and Gas Properties
The Company follows the full cost method of accounting whereby all costs related to the acquisition and development of oil and gas properties are capitalized into a single cost center (“full cost pool”). Such costs include lease acquisition costs, geological and geophysical expenses, internal costs directly related to exploration and development activities and costs of drilling both productive and non-productive wells. The Company capitalized $41,644, $76,973 and $123,753 of internal costs during the years ended December 31, 2012, 2011 and 2010, respectively. Additionally, the Company capitalized stock compensation expense related to our drilling consultants as further described in Note 8 - Stock-Based Compensation, herein. Costs associated with production and general corporate activities are expensed in the period incurred. During April 2010, the Company began charging a marketing fee related to the sale of its natural gas production to the wells in which it is the operator and, therefore, net income attributable to the outside working interest owners from such marketing activities of $112,301, $123,844 and $127,639 was recorded as a credit to proved properties during the years ended December 31, 2012, 2011 and 2010, respectively. Proceeds from property sales are generally credited to the full cost pool without gain or loss recognition unless such a sale would significantly alter the relationship between capitalized costs and the proved reserves attributable to a cost center. A significant alteration would typically involve a sale of 25% or more of the proved reserves related to a single full cost pool.
Depletion of exploration and development costs and depreciation of production equipment is computed using the units-of-production method based upon estimated proved oil and gas reserves. Costs included in the depletion base to be amortized include (i) all proved capitalized costs including capitalized asset retirement costs net of estimated salvage values, less accumulated depletion, (ii) estimated future development costs to be incurred in developing proved reserves; and (iii) estimated dismantlement and abandonment costs, net of estimated salvage values, that have not been included as capitalized costs because they have not yet been capitalized as asset retirement costs. The costs of unproved properties of $31,486,314 as of December 31, 2012, are withheld from the depletion base until it is determined whether or not proved reserves can be assigned to the properties. The properties are reviewed quarterly for impairment. If a determination is made that acreage will be expiring or that the Company does not plan to develop some of the acreage that is no longer considered to be prospective, an impairment of the acreage is recorded by reclassifying the costs to the full cost pool. The value of these acres for the purpose of recording the impairment is estimated by calculating a per acre value from the total unproved costs incurred for the applicable acreage divided by the total net acres owned by the Company. This per acre estimate is then applied to the acres that the Company does not plan to develop in order to calculate the impairment.
During the year ended December 31, 2012, the Company reclassified approximately $7,942,000 of acreage costs in Utah and California into proved property. This reclassification was comprised of a $7,000,000 decrease in the carrying value of its Utah acreage based upon an independent appraisal as of December 31, 2012 and $942,000 representing the value of leases that expired during 2012. During 2011, the Company reclassified $660,000 of acreage costs in Nevada into proved property as it relinquished control over this acreage to another party in exchange for a small overriding royalty interest on any future drilling projects. These costs were included in the ceiling test and depletion calculations during the quarter in which the reclassifications were made.
Total well costs are transferred to the depletable pool even when multiple targeted zones have not been fully evaluated. For depletion and depreciation purposes, relative volumes of oil and gas production and reserves are converted at the energy equivalent rate of six thousand cubic feet of natural gas to one barrel of crude oil. Estimated reserve quantities are affected by changes in commodity prices and actual well performance.
Under the full cost method of accounting, the ceiling test provides that capitalized costs less related accumulated depletion and deferred income taxes for each cost center may not exceed the sum of (1) the present value of future net revenue from estimated production of proved oil and gas reserves using current prices, excluding the future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet, at a discount factor of 10%; plus (2) the cost of properties not being amortized, if any; plus (3) the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any; less (4) income tax effects related to differences in the book and tax basis of oil and gas properties. Should the net capitalized costs for a cost center exceed the sum of the components noted above, a ceiling test write-down would be recognized to the extent of the excess capitalized costs exceed this ceiling limitation. The present value of estimated future net revenues is computed by applying the average, first-day-of-the-month oil and gas price during the 12-month period ended December 31, 2012 to estimated future production of proved oil and gas reserves as of the end of the period, less estimated future expenditures to be incurred in developing and producing the proved reserves assuming the continuation of existing economic conditions.
As of March 31, 2012, June 30, 2012, September 30, 2012 and December 31, 2012, the full cost pool exceeded the ceiling limitation based on the average first-day-of-the-month oil and gas prices of $82.58 per barrel and $2.94 per Mcf during the 12-month period ended March 31, 2012, $81.16 per barrel and $2.57 per Mcf during the 12-month period ended June 30, 2012, $80.35 per barrel and $2.23 per Mcf during the 12-month period ended September 30, 2012, and $80.25 per barrel and $2.15 per Mcf of gas during the 12-month period ended December 31, 2012. Therefore, impairment expense of $16,486,000 was recorded during the year ended December 31, 2012. No impairment expense related to the Company’s oil and gas properties was recorded during 2011 or 2010.
Wells in Progress
Wells in progress at December 31, 2011, represent the costs associated with the drilling of two wells in the Riverbend area of Utah. Since the wells had not been completed as of December 31, 2011, they were classified as wells in progress and were withheld from the depletion calculation and the ceiling test. The costs for these wells were transferred into proved property during January 2012 when the wells reached total depth and were cased and became subject to depletion and the ceiling test calculation in subsequent periods.
Capitalized Interest
The Company capitalizes interest costs to oil and gas properties on expenditures made in connection with exploration and development projects that are not subject to current depletion. Interest is capitalized only
for the period that activities are in progress to bring these projects to their intended use. No interest was capitalized during the three years ended December 31, 2012.
Facilities and Equipment
The Company’s oil and gas equipment is depreciated using the straight-line method over an estimated useful life of three to ten years. The rental of the equipment owned by the Company is charged to the wells that are operated by the Company and, therefore, the net activity attributable to the outside working interest owners from the equipment rental of $(28,080), $(93,208) and $(16,109) was recorded as an adjustment to proved properties during the years ended December 31, 2012, 2011 and 2010, respectively.
Deferred Financing Costs
Deferred financing costs represent the costs associated with the issuance of financial instruments. The Company recorded amortization expense of $272,605, $258,456 and $13,888,901 related to these costs during the years ended December 31, 2012, 2011 and 2010, respectively. Expenses in 2012 and 2011 related to the amortization of the costs for the issuance of the 2015 Notes (see Note 5 - Convertible Senior Notes, herein). Expenses incurred in 2010 included the pro-rata portion of the debt issuance costs expensed for a conversion of 30% of the outstanding 2015 Notes.
Forward Sales Contracts
During March 2010, per the Base Contract for Sale and Purchase of Natural Gas that the Company has with Anadarko Energy Services Company, dated December 1, 2007, the Company entered into a term sales and transportation transaction to sell up to 50,000 MMBtu per day of its gross production through 2013 from the Uinta Basin. The transaction contains two pricing mechanisms: (1) up to 25,000 MMBtu per day will be priced at the NW Rockies first of month price and (2) up to 25,000 MMBtu per day will be priced at the first of the month index price as published by Gas Daily for the North West Wyoming Poll Index price. The Company accounts for its agreement to physically settle its production as an executory contract. The Company does not believe that the loss of this contract would materially affect its business because there are other potential purchasers in the areas in which the Company sells its production; however, the Company may not be able to find other purchasers who would purchase its production on terms comparable to its current arrangements.
Commodity Derivatives
From time to time, the Company has used commodity derivative instruments to provide a measure of stability to its cash flows in an environment of volatile oil and gas prices and to manage its exposure to commodity price risk. The Company records all commodity derivative instruments at fair value within the accompanying consolidated balance sheets. The Company’s management decided not to use hedge accounting under the accounting guidance for its commodity derivatives and therefore, the changes in fair value are recognized currently in earnings. See Note 6 - Derivatives, herein.
Warrants
On June 15, 2011, the Company issued warrants (“June Warrants”) to purchase 18,750,000 shares of common stock and on August 3, 2011, the Company issued warrants (“August Warrants”) to purchase 11,500,000 shares of common stock. The Warrants are exercisable immediately for a term of sixty months, beginning at issuance, at an initial exercise price of $0.35 per share; however, the exercise price and number of shares of common stock issuable on exercise of the Warrants are subject to adjustment in the event of any stock split, reverse stock split, stock dividend, recapitalization, reorganization or similar transaction. If the
Company makes a distribution of its assets to all of its stockholders, holders of the Warrants may be entitled to participate. In the event of a Fundamental Transaction (as defined in the Warrants), at the election of a holder of a Warrant, the Company may be required to purchase the holder’s Warrant for cash in an amount equal to the value of the remaining unexercised portion of the Warrant. As a result, the Warrants are accounted for as a liability on the Company’s consolidated balance sheets with changes in their fair value reported in earnings. Subject to certain exceptions, if the average of the daily volume weighted-average price of a share of common stock for some period of time equals or exceeds 200% of the initial exercise price of the Warrants, and if at the time of such measurement the Equity Conditions (as defined in the Warrants) are satisfied, then the Company may, subject to certain conditions, require the holders of the Warrants to exercise.
Asset Retirement Obligation
The Company accounts for its future asset retirement obligations by recording the fair value of the liability during the period in which it was incurred. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. The increase in carrying value of a property associated with the capitalization of an asset retirement cost is included in proved oil and gas properties in the consolidated balance sheets. The Company depletes the amount added to proved oil and gas property costs using the units-of-production method. The Company’s asset retirement obligation consists of costs related to the plugging of wells, removal of facilities and equipment and site restoration on its oil and gas properties. The asset retirement liability is allocated to operating expense using a systematic and rational method.
See Note 4 - Asset Sales and Acquisitions, herein, for discussion of property dispositions.
Deferred Income from Sale of Assets
The deferred income from sale of assets represents the excess of proceeds received over the carrying value that was recorded in connection with the sale of the Company’s gathering assets and evaporative facilities in February 2010. This income is being amortized over the fifteen-year terms of the gathering and salt water disposal contracts which were entered into at the time of the sale.
Off Balance Sheet Arrangements
From time to time, the Company enters into off-balance sheet arrangements and transactions that can give rise to off-balance sheet obligations. As of December 31, 2012, the off-balance sheet arrangements and transactions that the Company had entered into included undrawn letters of credit, operating lease agreements, gathering, compression, processing and water disposal agreements and gas transportation commitments. See Note 16 - Commitments, herein, for additional discussion regarding certain gas transportation and processing agreements.
Revenue Recognition
The Company records revenues from the sale of natural gas and crude oil when delivery to the customer has occurred, title has transferred and collectability is reasonably assured. This occurs when oil or gas has been delivered to a pipeline or a tank lifting has occurred.
The Company may have an interest with other producers in certain properties, in which case the Company uses the sales method to account for gas imbalances. Under this method, revenue is recorded on the basis of gas actually sold by the Company. In addition, the Company records revenue for its share of gas sold by other owners that cannot be volumetrically balanced in the future due to insufficient remaining reserves. The Company also reduces revenue for other owners’ gas sold by the Company that cannot be volumetrically balanced in the future due to insufficient remaining reserves. The Company’s remaining over- and under-produced gas balancing positions are considered in the Company’s proved oil and gas reserves. Gas imbalances at December 31, 2012 and 2011 were not significant.
Computation of Net Income (Loss) per Share
Basic net income (loss) per share is computed by dividing net income (loss) attributable to the common stockholders by the weighted-average number of common shares outstanding during the reporting period. The shares of restricted common stock granted to certain officers and employees of the Company are included in the computation of basic net income (loss) per share only after the shares become fully vested. Diluted net income (loss) per share of common stock includes both the vested and unvested shares of restricted stock. Diluted net income or loss per common share of stock is computed by dividing adjusted net income by the diluted weighted-average common shares outstanding. Potentially dilutive securities for the diluted earnings per share calculation consist of (i) unvested shares of restricted common stock, (ii) in-the-money outstanding options and Warrants to purchase the Company’s common stock, (iii) outstanding Series C Convertible Preferred Stock, par value $0.001 per share (“Preferred Stock”), which are convertible into shares of the Company’s common stock, and (iv) the Company’s outstanding 2015 Notes which are convertible into shares of Preferred Stock and common stock.
The treasury stock method, which assumes that the increase in the number of shares is reduced by the number of shares that could have been repurchased by the Company with the proceeds from the exercise of the options (which repurchases were assumed to have been made at the average market price of the common shares during the reporting period), is used to measure the dilutive impact of stock options, shares of restricted common stock and shares into which the 2015 Notes and Preferred Stock are convertible.
Net income (loss) per share information is determined using the two-class method, which includes the weighted-average number of common shares outstanding during the period and other securities that participate in dividends (“participating security”). The Company considers the Preferred Stock to be a participating security because it includes rights to participate in dividends with the common stock. In applying the two-class method, earnings are allocated to both common stock shares and the Preferred Stock common stock equivalent shares based on their respective weighted-average shares outstanding for the period. Losses are not allocated to Preferred Stock shares. The table below sets forth the computations of basic and diluted net income (loss) per share for the years ended December 31, 2012, 2011 and 2010.
The following were excluded from the computation of diluted earnings (loss) per common share as they did not have a dilutive effect.
Use of Estimates
The preparation of the financial statements for the Company in conformity with U.S. generally accepted accounting principals (“GAAP”) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from these estimates.
The Company’s financial statements are based on a number of significant estimates, including oil and gas reserve quantities which are the basis for the calculation of depreciation, depletion and impairment of oil and gas properties, timing and costs associated with its retirement obligations, estimates of the fair value of derivative instruments, estimates used in stock-based compensation calculations and impairments to unproved property and to proved oil and gas properties.
Reclassifications
Certain reclassifications have been made to prior years’ amounts to conform to the classifications used in the current year. Such reclassifications had no effect on the Company’s net loss for the period presented.
Other Comprehensive Income (Loss)
The Company does not have any items of other comprehensive income (loss) for the years ended December 31, 2012, 2011 and 2010. Therefore, total comprehensive income (loss) is the same as net income (loss) for these periods.
Income Taxes
The Company uses the asset and liability method of accounting for income taxes under which deferred tax assets and liabilities are recognized for the future tax consequences of temporary differences between the accounting bases and the tax bases of the Company’s assets and liabilities. The deferred tax assets and liabilities are computed using enacted tax rates in effect for the year in which the temporary differences are expected to reverse.
The Company’s policy is to recognize penalties and interest, if any, related to uncertain tax positions as general and administrative expense. The Company files income tax returns in the U.S. federal jurisdiction and various states. There are currently no federal or state income tax examinations underway for these jurisdictions. Furthermore, the Company is no longer subject to U.S. federal income tax examinations by the Internal Revenue service for tax years before 2009 and for state and local tax authorities for years before 2008.
Stock Compensation
The Company recognizes compensation cost for its common stock options and restricted stock grants as equity based awards based on estimated fair value of the award and records compensation expense over the requisite service period. The Company accounts for its stock appreciation rights (“SARs”) as liability based awards and accordingly recognizes the fair value of the vested SARs each reporting period. See Note 8 -Stock-Based Compensation, herein for further discussion.
Recently Issued Accounting Pronouncements
Effective January 1, 2012, the Company adopted Accounting Standards Update (“ASU”) No. 2011-04, “Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and International Financial Reporting Standards.” The adoption of ASU 2011-04 did not have a significant impact on the Company’s consolidated financial position or results of operations.
NOTE 4 - ASSET SALES AND ACQUISITIONS
Uinta Basin Joint Venture
On March 22, 2012, the Company closed a transaction (the “Uinta Basin Transaction”) whereby, pursuant to the Purchase and Sale Agreement (the “Purchase Agreement”) dated February 23, 2012, between the Company’s wholly-owned subsidiary, Gasco Production Company, and Wapiti Oil & Gas II, L.L.C. (“Wapiti”), and a Closing Agreement (the “Closing Agreement”) dated March 22, 2012 relating to the Purchase Agreement, the Company (i) sold to Wapiti an undivided 50% of its interest in certain of its Uinta Basin producing oil and gas assets for $18.0 million in cash and $1.19 million in the form of a
promissory note receivable from Wapiti, which was repaid in full during the second quarter of 2012, and (ii) transferred to Wapiti an undivided 50% of its interest in its Uinta Basin non-producing oil and gas assets in exchange for, among other agreements, Wapiti’s commitment to fund $30.0 million of the drilling and completion costs associated with the exploration and development of the subject assets.
As a part of the Uinta Basin Transaction, Gasco Production Company entered into a Development Agreement (the “Development Agreement”) with Wapiti, which includes terms and conditions of a drilling program agreed to by the parties.
Of Wapiti’s $30.0 million funding commitment, $15.0 million will be paid on behalf of the Company, and the Company has agreed to provide an additional $7.5 million of drilling and completion costs. Accordingly, the total program will be $37.5 million. If the Company is not able to pay its share of the above costs, it may lose certain rights granted under the Development Agreement and related operating agreements, including the right to continue as operator or contract operator of the properties, the right to make proposals or elect to participate in operations under the Development Agreement or any operating agreement, the right to call, attend and vote at meetings of the operating committee, the right to transfer its interest in the properties and the joint venture, the right to acquire Wapiti’s interest in the properties under the right of first offer provisions of the Development Agreement and the right to acquire its pro rata share of additional properties acquired by Wapiti within the area of mutual interest identified in the Development Agreement. We have not incurred any costs to date and there is substantial doubt regarding our ability to fund our share of the drilling and completion costs.
The drilling and completion program will continue until Wapiti’s funding commitment has been fully expended or for a shorter period if the Operating Committee (as defined below) votes to cease the drilling program after Wapiti has expended $10.0 million on drilling and completion costs related to the program wells (the “Drilling Term”).
With respect to wells drilled pursuant to the drilling program, the net revenue interest attributable to such wells from the closing through the time when the cumulative proceeds received by Wapiti from such wells equals the amount of costs actually paid by Wapiti in respect of such wells and the drilling program (such time, “Payout”), will be allocated 32.5% to the Company and 67.5% to Wapiti. After Payout, the net revenue interest will be allocated in proportion to the actual net revenue interests of the parties in such wells. With respect to each well drilled pursuant to the drilling program, (i) all drilling and completion costs will be borne (a) during the Drilling Term, 20% by the Company and 80% by Wapiti, (b) after the Drilling Term but before Payout, 32.5% by the Company and 67.5% by Wapiti, and (c) after Payout, in proportion to the actual working interests of the parties in such wells, and (ii) all other working interest costs will be borne (x) before Payout, 32.5% by the Company and 67.5% by Wapiti, and (y) after Payout, in proportion to the actual working interests of the parties in such wells.
Subject to the terms of the Development Agreement, the Company will manage the operations contemplated by the drilling program. Except for the subject assets that are already subject to joint operating agreements with third parties, the operation of (i) a portion of the subject assets will be subject to an agreed upon joint operating agreement (a “JOA”), which names Gasco Production Company as operator of record, and (ii) the remaining portion of the subject assets will be subject to an agreed upon JOA, which names Wapiti as operator of record. Gasco Production Company and Wapiti also entered into a contract operating agreement naming Gasco Production Company as contract operator with respect to the portion of the subject assets for which Wapiti is named as operator of record. However, to the extent that Gasco Production Company, as operator under these agreements, becomes insolvent, bankrupt or is placed into receivership, it will be deemed to have resigned as operator or the other party may have a termination right. The Company and Wapiti have formed an Operating Committee (the “Operating Committee”) to oversee generally the drilling program and operations in the project area and to approve
certain matters specified in the Development Agreement. The Operating Committee consists of two members from each of the Company and Wapiti, with the members appointed by each party having an aggregate 50% vote.
The Development Agreement also contains transfer restrictions on each of our and Wapiti’s ability to transfer its respective interests in the subject assets. The Development Agreement also contains a customary area of mutual interest provision covering the Project Area. With certain limited exceptions, the Development Agreement will remain in effect during the Drilling Term; however, after the six-month anniversary of the end of the Drilling Term, the Development Agreement may be terminated by either the Company or Wapiti upon six months’ advance notice.
Due to low natural gas prices and permitting delays, the Company did not drill any natural gas wells in Utah from the closing of the Uinta Basin Transaction through the remainder of 2012.
The foregoing description of the Uinta Basin Transaction, including the Purchase Agreement, the Closing Agreement and the Development Agreement, do not purport to be complete and are qualified in their entirety by reference to the full text of the Purchase Agreement, the Closing Agreement and the Development Agreement.
The Company used approximately $10.5 million of the proceeds from the transaction to repay the borrowings under its prior revolving credit facility. The Company planned to use the remaining proceeds for its capital expenditures consisting of approximately $5.0 million for additional investment in existing and new California oil and gas prospects in the San Joaquin Basin as well as for working capital, acquisitions of oil and natural gas properties and other general corporate purposes. However, due to low natural gas prices and permitting delays, the Company did not drill any natural gas wells in Utah during the remainder of 2012.
The sale of the proved property in the Uinta Basin Transaction was recorded by recognizing a gain of $2,567,574 rather than recording a credit to the full cost pool for the proceeds because this method would significantly alter the relationship between capitalized costs and the proved reserves attributable to the cost center.
No adjustments were made to the carrying value of the unproved properties upon the closing of the Uinta Basin Transaction. Rather as the wells are drilled, the cost basis of the unproved property associated with each well drilled will be reclassified from unproved property to the full cost pool to be depleted and included in the ceiling test. The cost basis will be determined based on a per acre valuation multiplied by the number of acres for each drilling location.
The following unaudited pro forma information is presented as if the Uinta Basin Transaction had an effective date of January 1, 2010, and is not necessarily indicative of either future results of operations or results that might have been achieved had the transaction been consummated as of January 1, 2010.
Working Interest Acquisition
During December 2012, the Company acquired additional working interests in 32 producing wells in the Riverbend area of Utah in which the Company has a working interest and operates for $177,620. The acquired interests range from 4% to 10% per well with an average of 8% per well.
Prospect Fee
During January 2012, the Company entered into an arrangement with an exploration and production company which operates in California, pursuant to which the Company received a $750,000 prospect fee related to certain of its California acreage. The fee reimbursed costs that the Company has invested in the area and provides it with a potential carried interest of 20% in one well to be drilled on the acreage. The proceeds were recorded as a credit to unproved properties during the year ended December 31, 2012.
NOTE 5 - CONVERTIBLE SENIOR NOTES
As of December 31, 2012, the Company had $45,168,000 aggregate principal amount of 2015 Notes outstanding.
The 2015 Notes are governed by an indenture, dated as of June 25, 2010 (the “2015 Indenture”), by and between the Company and Wells Fargo Bank, National Association, as trustee (the “Trustee”) The 2015 Notes were issued on June 25, 2010 (the “Issue Date”) pursuant to the exemption from the registration requirements of the Securities Act of 1933 (the “Securities Act”) provided by Section 4(2) and Regulation D thereunder. The 2015 Notes have a maturity date of October 5, 2015.
The 2015 Notes bear interest at a rate of 5.50% per annum, payable in cash semi-annually in arrears on April 5th and October 5th of each year. The Company’s failure to make an interest payment on the 2015 Notes, if not cured within 30 days, or the delisting of the Company’s common stock from the Exchange, would result in a default under the 2015 Indenture, which would permit the holders of the 2015 Notes to accelerate repayment of the 2015 Notes.
The 2015 Notes are convertible, at the option of the holder, at any time prior to maturity, into shares of common stock or, at the election of such holder, into Preferred Stock. The initial conversion price for converting the 2015 Notes into common stock is $0.60 per share of common stock, which is equal to a conversion rate of 1,666.6667 shares of common stock per $1,000 principal amount of 2015 Notes. The conversion rate is subject to adjustment in certain circumstances and limitations. The initial conversion price for converting the 2015 Notes into Preferred Stock is $100, which is equal to a conversion rate of ten shares of Preferred Stock per $1,000 principal amount of 2015 Notes. Pursuant to the 2015 Indenture, a holder may not convert all or any portion of such holder’s 2015 Notes into common stock to the extent that such holder and its affiliates would, after giving effect to such conversion, beneficially own more than 4.99% of the outstanding shares of common stock (the “Maximum Ownership Percentage”), provided that such holder, upon not less than 61 days’ prior written notice to the Company, may increase the Maximum Ownership Percentage applicable to such holder (but, for the avoidance of doubt, not for any subsequent or other holder) to 9.9% of the outstanding shares of common stock.
The Company may redeem the 2015 Notes in whole or in part for cash at any time at a redemption price equal to 100% of the principal amount of the 2015 Notes plus any accrued and unpaid interest and liquidated damages, if any, on the 2015 Notes redeemed to but not including the redemption date, if the closing price of the Company’s common stock equals or exceeds 150% of the conversion price for at least 20 trading days within the consecutive 30 trading day period ending on the trading day before the redemption date and all of the Equity Conditions (as defined in the 2015 Indenture) are satisfied (or waived in writing by the holders of a majority in aggregate principal amount of the 2015 Notes then outstanding). If a holder elects to convert its 2015 Notes in connection with such a provisional redemption by the Company, the Company will make an additional payment equal to the total value of the aggregate amount of the interest otherwise payable on the 2015 Notes to be calculated from the last day through which interest was paid on the 2015 Notes through and including the third anniversary of the Issue Date and discounted to the present value of such payment; provided, however, that at the Company’s option, in lieu of such discounted cash payment, the Company may deliver shares of Preferred Stock having a value equal to such discounted cash payment. The value of each share of Preferred Stock to be delivered shall be deemed equal to the product of (i) the average closing price per share of common stock over the ten trading day period ending on the trading day before the redemption date, and (ii) the number of whole shares of common stock into which each share of Preferred Stock is then convertible (without giving effect to any limitations on conversion in the Certificate of Designations of the Preferred Stock) (subject to certain conditions).
Upon a change of control (as defined in the 2015 Indenture), each holder of 2015 Notes may require the Company to repurchase some or all of its 2015 Notes at a repurchase price equal to 100% of the aggregate principal amount of the 2015 Notes to be repurchased plus accrued and unpaid interest and liquidated damages, if any, to but not including the date of purchase, plus, in certain circumstances, a make whole premium. The Company may pay the change of control purchase price and/or the make whole premium in cash or shares of Preferred Stock at the Company’s option. In addition, in the case of the make whole premium, at the Company’s option, the Company may pay such premium in the same form of consideration used to pay for the shares of common stock in connection with the transaction constituting the change of control.
The 2015 Indenture contains usual and customary covenants limiting the Company’s ability to incur additional indebtedness, with certain exceptions, or liens on its property or assets, restricting its ability to make dividends or other distributions, requiring its domestic subsidiaries to guarantee the 2015 Notes, requiring it to list the shares of common stock that may be issued upon conversion of the 2015 Notes and the Preferred Stock on the NYSE MKT LLC or any other U.S. national or regional securities exchange on which the common stock is then listed, and requiring it to use reasonable best efforts to obtain
stockholder approval for the issuance of shares of common stock upon conversion of the 2015 Notes and upon conversion of any shares of Preferred Stock issuable upon conversion of the 2015 Notes.
The 2015 Notes are unsecured and unsubordinated and rank on a parity in right of payment with all of the Company’s existing and future senior unsecured indebtedness, rank senior in right of payment to any of the Company’s existing and future subordinated indebtedness, and are effectively subordinated in right of payment to any of the Company’s secured indebtedness or other obligations to the extent of the value of the assets securing such indebtedness or other obligations. The Company’s subsidiaries guarantee the 2015 Notes pursuant to a Guaranty Agreement dated as of June 25, 2010, by and among Gasco Production Company, Riverbend Gas Gathering, LLC, and Myton Oilfield Rentals, LLC, in favor of the Trustee.
The debt discount that was recognized in connection with the 2015 Notes is being accreted to interest expense under the effective interest method at a rate of 26.3%. The unamortized discount as of December 31, 2012 and 2011 was $18,530,539 and $22,574,687, respectively.
NOTE 6 - DERIVATIVES
From time to time, the Company uses commodity derivative instruments to provide a measure of stability to its cash flows in an environment of volatile oil and gas prices and to manage its exposure to commodity price risk. As of December 31, 2012, natural gas derivative instruments consisted of one costless collar agreement for production from January 1, 2012 through December 31, 2012. During June 2012, the Company monetized this contract for net proceeds of $677,868. Prior to the monetization, the costless collar contained a fixed floor price (purchase put) and ceiling price (written call). The Company received the difference between the published index price and the floor price if the index price was below the floor price. The Company paid the difference between the ceiling price and the index price only if the index price was above the ceiling price. If the index price was between the ceiling and the floor prices, no amounts were paid or received.
On June 15, 2011, the Company issued the June Warrants to purchase 18,750,000 shares of common stock and on August 3, 2011, the Company issued the August Warrants to purchase 11,500,000 shares of common stock. The Warrants have an initial exercise price of $0.35 per share (subject to adjustment) and sixty-month term. The Warrants contain a contingent cash settlement provision at the option of the holder and accordingly, are classified as a derivative liability and are subject to the classification and measurement standards for derivative financial instruments.
The following table details the fair value of the derivatives recorded in the consolidated balance sheets:
The table below summarizes the realized and unrealized gains and losses related to the Company’s derivative instruments for the years ended December 31, 2012, 2011 and 2010.
These realized and unrealized gains and losses are recorded in the accompanying consolidated statements of operations as derivative gains (losses).
NOTE 7 - GAS PROCESSING AGREEMENT
On September 21, 2011, the Company entered into a Gas Processing Agreement (the “Chipeta Processing Agreement”) with Chipeta Processing LLC (“Chipeta”) pursuant to which the Company dedicated certain of its natural gas production from its acreage in Utah to Chipeta for processing, and Chipeta agreed to process all natural gas production from such assets through facilities and related equipment that Chipeta constructed.
The primary term of the Chipeta Processing Agreement is ten years, beginning after the in-service date of a 300 MMcf/d cryogenic processing facility to be built by Chipeta. The primary term will be extended for one-year terms unless terminated by either party giving 180 days’ notice prior to the expiration of the then-current term. The cryogenic processing facility was completed and placed in service on February 7, 2013.
Pursuant to the Chipeta Processing Agreement, the Company reserved 25,000 Mcf/d of capacity in the Chipeta processing plant for cryogenic processing. Under this agreement, the Company committed to deliver, on average, at least 90% of its contracted cryogenic capacity of 25,000 Mcf/d during each monthly accounting period. The Company agreed to pay specified processing fees per MMBtu as well as a pro rata share of all applicable electric compression costs, subject to escalation on an annual basis. The Company may also be required to make periodic deficiency payments to Chipeta for any shortfalls from the specified minimum volume commitments.
Historically, the Company’s natural gas production had been gathered and processed by Monarch Natural Gas, LLC, a Delaware limited liability company (“Monarch”) pursuant to the Gas Gathering and Processing Agreement effective March 1, 2010 between Monarch and the Company (the “Monarch Processing Agreement”).
On March 22, 2012, the Company entered into an Amended and Restated Gas Gathering and Processing Agreement (the “Amended and Restated Monarch Agreement”) with Monarch in which Monarch agreed to, among other things, (a) release and waive its rights to process the first 50,000 MMBtu/day of the Company’s gas delivered to Monarch’s gathering system pursuant to the Amended and Restated Monarch Agreement (the “Excluded Production”) and (b) retain all processing rights for all gas volumes produced from certain of the Company’s reserves in excess of the Excluded Production. The Excluded Production may be reduced if the Company fails to meet certain drilling investment targets. The Company is committed to deliver to Monarch for gathering a minimum of 25,000 Mcf/day and it is obligated to pay for any shortfall following the end of each quarterly period, measured by the shortfall quantity for the quarter multiplied by the then-current gathering and processing fees under the agreement.
In connection with the Amended and Restated Monarch Agreement, we also entered into the Questar Wet Line Agreement (the “QPC Transportation Agreement”), dated September 20, 2011, by and between Questar Pipeline Company (“QPC”), pursuant to which we agreed to enter into separate transportation services agreements for firm transportation services. We are currently committed to deliver to QPC for transportation services a minimum of 25,000 MMBtu/day.
See Note 16 - Commitments for further discussion.
NOTE 8 - STOCK-BASED COMPENSATION
The Company has outstanding common stock options, SARs and restricted stock issued under its equity incentive plans. The Company measures the fair value at the grant date for stock option grants and restricted stock awards and records compensation expense over the requisite service period. The expense recognized over the service period includes an estimate of the awards that will be forfeited. Gasco assumes no forfeitures for employee awards based on the Company’s historical forfeiture experience. The Company accounts for its SARs as liability based awards and accordingly the Company recognizes the fair value of the vested SARs each reporting period. The fair value of stock options and SARs is calculated using the Black-Scholes option-pricing model and the fair value of restricted stock is based on the fair value of the stock on the date of grant.
The Company accounts for stock compensation arrangements with non-employees using a fair value approach. Under this approach, the stock compensation related to the unvested stock options issued to non-employees is recalculated at the end of each reporting period based upon the fair value on that date. During the years ended December 31, 2012, 2011 and 2010, the Company recognized stock-based compensation as follows:
The Company did not recognize a tax benefit from stock-based compensation expense because the Company considers it more likely than not that the related deferred tax assets, which have been reduced by a full valuation allowance, will not be recognized.
The Company uses the Black-Scholes option-pricing model to estimate the fair value of the options at the grant date. The fair value of options granted to the Company’s employees and directors during 2012, 2011 and 2010 was calculated using the following assumptions:
The weighted average grant-date fair value of options granted to employees and directors during 2012, 2011 and 2010 was $0.12, $0.08 and $0.23, respectively.
The expected stock price volatility assumption was determined using the historical volatility of the Company’s common stock over the expected life of the option.
Stock Options
During the year ended December 31, 2012, the Company granted 2,096,485 options to purchase common stock with exercise prices ranging from $0.16 to $0.30 per share. These options have a two-year vesting period and expire five years from the grant date.
During the year ended December 31, 2011, the Company granted 751,000 options to purchase common stock with exercise prices of $0.17 to $0.25. These options vest in equal portions over the following two-year period and expire five years from the grant date.
During the year ended December 31, 2010, the Company granted 1,371,000 options to purchase 50,000, 175,000, 646,000 and 500,000 shares of common stock with exercise prices of $0.34, $0.35, $0.36 and $0.37 per share, respectively. These options have a one- or two-year vesting period and expire five years from the grant date.
The following table summarizes the stock option activity in the equity incentive plans during the years ended December 31, 2012, 2011 and 2010:
The following table summarizes information related to the outstanding and vested options as of December 31, 2012:
The aggregate intrinsic value in the table above is based on the Company’s closing common stock price of $0.07 as of December 31, 2012, which would have been received by the option holders had all option holders exercised their options as of that date.
There were no options exercised during the years ending December 31, 2012, 2011 and 2010.
The Company settles employee stock option exercises with newly issued common shares. SARs are settled with cash equal to the difference between the fair market value of the stock and the exercise price on the date of grant.
As of December 31, 2012, there was $241,557 of total unrecognized compensation cost related to non-vested options and SARs granted under the Company’s equity incentive plans. That cost is expected to be recognized over a period of 2.4 years.
The following table summarizes the stock options outstanding at December 31, 2012:
SARs
Effective October 1, 2011, the Company’s non-employee directors agreed to reduce their monthly compensation and in exchange, on October 5, 2011, the Company granted SARs related to a total of 500,000 shares of the Company’s common stock to these directors. As of December 31, 2011, the SARs were recorded as a liability of $10,924. The SARs provided the right to receive a lump sum cash payment equal to the value of the product of (a) the excess of (i) the fair market value of one share of common stock on the date of exercise, over (ii) $0.25, which is an amount greater than the closing price of a share of common stock on the date of grant, multiplied by (b) the number of shares as to which an award has been exercised (“Appreciation Amount”). The SARs vested on January 31, 2012 and were automatically exercised on February 1, 2012. The fair market value of the common stock on the date of exercise was below $0.25 per share and therefore the Appreciation Amount was zero and no cash payment was made.
Effective February 28, 2012, the Company granted another SARs award (“February SARs”) related to a total of 1,000,000 shares of its common stock to these directors. As of December 31, 2012, the liability for February SARs was approximately zero. The February SARs provided the right to receive a lump sum cash payment equal to the value of the product of (a) the excess of (i) (A) the fair market value of one share of common stock on the date of exercise or (B) $2.00, whichever was less, over (ii) $0.30, which was an amount greater than the closing price of a share of common stock on the date of grant, multiplied by (b) the number of shares as to which an award has been exercised. The February SARs vested on
January 31, 2013 and were automatically exercised on February 1, 2013. The fair market value of the common stock on the date of exercise was below $0.25 per share and therefore the Appreciation Amount was zero and no cash payment was made.
Restricted Stock
The following table summarizes the restricted stock activity for the years ending December 31, 2012, 2011 and 2010:
The total grant date fair value of the restricted shares vested during the years ending December 31, 2012, 2011 and 2010 was $35,460, $64,204 and $197,075, respectively.
As of December 31, 2012, there was $64,347 of total unrecognized compensation cost related to non-vested restricted stock granted under the Company’s stock plans. That cost is expected to be recognized over a weighted-average period of 2.4 years.
NOTE 9 - OIL AND GAS PROPERTY
The Company’s oil and gas properties are summarized in the following table:
The following table presents information regarding the Company’s net costs incurred in the purchase of proved and unproved properties and in exploration and development activities:
At December 31, 2012 and 2011, the Company’s unproved properties consist of leasehold acquisition and exploration costs in the following areas:
During the year ended December 31, 2012, the Company reclassified approximately $7,942,000 of acreage costs in Utah and California into proved property. This reclassification was comprised of a $7,000,000 decrease in the carrying value of its Utah acreage based upon an independent appraisal as of December 31, 2012 and $942,000 representing the value of leases that expired during 2012. During 2011, the Company reclassified $660,000 of acreage costs in Nevada into proved property as it relinquished our control over this acreage to another party in exchange for a small overriding royalty interest on any future drilling projects. These costs were included in the ceiling test and depletion calculations during the quarter in which the reclassifications were made.
Depreciation, depletion and amortization expense per Mcfe was $1.07, $0.91 and $0.82 for the years ended December 31, 2012, 2011 and 2010, respectively. Impairment expense was $6.44 per Mcfe during the year ended December 31, 2012. No impairment expense was recorded during the years ended December 31, 2011 and 2010.
The following table sets forth a summary of unproved oil and gas property costs as of December 31, 2012, by the year in which such costs were incurred.
The Company believes that the majority of its unproved costs will become subject to depletion within the next five years, by proving up reserves relating to the acreage through exploration and development activities, by impairing the acreage that will expire before the Company can explore or develop it further, or by making decisions that further exploration and development activity will not occur.
NOTE 10 - CREDIT FACILITY
The Company’s prior $250 million revolving credit facility matured on June 29, 2012 and was repaid in full.
While the Company has attempted to secure a replacement facility, as of the date of this Annual Report, it has been unable to do so on acceptable terms and is no longer actively in discussions to obtain a replacement facility. There can be no assurance that the Company will be able to adequately finance its operations or execute its existing short-term and long-term business plans, and its liquidity and results of operations are likely to be materially adversely affected if the Company is unable to generate sufficient operating cash flows, secure additional capital or otherwise pursue a strategic restructuring, refinancing or other transaction to provide it with additional liquidity.
NOTE 11 - FAIR VALUE MEASUREMENTS
The authoritative guidance establishes a hierarchy for inputs used in measuring fair value that maximizes the use of observable inputs and minimizes the use of unobservable inputs by requiring that the most observable inputs be used when available. Observable inputs are inputs that market participants would use in pricing the asset or liability developed based on market data obtained from sources independent of the Company. Unobservable inputs are inputs that reflect the Company’s assumptions of what market participants would use in pricing the asset or liability developed based on the best information available in the circumstances. The hierarchy is broken down into three levels based on the reliability of the inputs as follows:
Level 1: Quoted prices are available in active markets for identical assets or liabilities;
Level 2: Quoted prices in active markets for similar assets and liabilities that are observable for the asset or liability; or
Level 3: Unobservable pricing inputs that are generally less observable from objective sources, such as discounted cash flows models or valuations.
The financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. The Company’s policy is to recognize transfers in and/or out of fair value hierarchy as of the end of the reporting period for which the event or change in circumstances caused the transfer. The Company has consistently applied the valuation techniques discussed below in all periods presented.
The following table presents the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2012 and 2011 by level within the fair value hierarchy:
As of December 31, 2012, the Company’s warrant derivative financial instrument is comprised of the Warrants issued by the Company to purchase 30,250,000 shares of common stock. The Warrants are valued using a binomial lattice-based valuation model and are classified as Level 3 in the fair value hierarchy. The lattice-based valuation technique is utilized because it embodies all of the requisite assumptions (including the underlying price, exercise price, term, volatility, and risk-free interest-rate) that are necessary to measure the fair value of these instruments. The valuation policies are determined by the Chief Accounting Officer and are approved by the Chief Executive Officer. Fair value measurements are discussed with the Company’s audit committee, as deemed appropriate. Each quarter, the Chief Accounting Officer and the Chief Executive Officer update the inputs used in the fair value calculations and internally review the changes from period to period for reasonableness. The Company uses data from its peers as well as from external sources in the determination of the volatility and risk free interest rates used in the fair value calculations. A sensitivity analysis is performed as well to determine the impact of the inputs on the ending fair value estimate. Estimating fair values of derivative financial instruments requires the development of significant and subjective estimates that may, and are likely to, change over the duration of the instrument due to both internal and external market factors. In addition, option-based techniques are highly sensitive to volatility assumptions, particularly since the trading price of the Company’s common stock has a high-historical volatility. With all other factors remaining constant as of December 31, 2012:
(i) the warrant derivative liability would remain unchanged if the trading price of Gasco’s common stock was reduced to zero, and would increase by approximately $1.9 million for a $0.10 increase in the trading price of our common stock.
(ii) the warrant derivative liability would remain unchanged with a 10% increase in the volatility rate and would decrease by approximately $302,000 with a 10% decrease in the volatility rate.
A summary of the Warrants issued by the Company is as follows:
The significant assumptions used in the valuation of the warrant derivative liability are as follows:
The following table sets forth a reconciliation of changes in the fair value of financial liabilities classified as Level 3 in the fair value hierarchy:
The carrying amounts of cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities approximate fair values because of the short-term maturities and or liquid nature of these assets and liabilities. The estimated fair value of the 2015 Notes of $28,833,000 and $31,443,000 as of December 31, 2012 and 2011, respectively, was determined using the income valuation technique and option pricing model. This valuation is classified as a Level 3 in the fair value hierarchy as it relies primarily on unobservable pricing inputs.
NOTE 12 - STOCKHOLDERS’ EQUITY
The Company’s capital stock as of December 31, 2012 and 2011 consists of 600,000,000 authorized shares of common stock, par value $0.0001 per share, 20,000 authorized shares of Series B Convertible Preferred stock, par value $0.001 per share, and 2,000,000 authorized shares of Series C Convertible Preferred stock (“Preferred Stock”).
Series B Convertible Preferred Stock
As of December 31, 2012 and 2011, the Company had no shares of Series B Preferred Stock issued and outstanding.
Series C Convertible Preferred Stock
As of December 31, 2012 and 2011, the Company had 182,065 and 191,000 shares, respectively, of Preferred Stock issued and outstanding. The Preferred Stock is entitled to receive cash dividends and other distributions declared on the common stock, as well as distributions upon liquidation, dissolution or any other winding up event, in each case as set forth in the Certificate of Designations. The Preferred Stock does not have any right or power to vote on any question or in any proceeding or to be represented at or to receive notice of any meeting of holders of capital stock of the Company, except as required by law. The Preferred Stock may not be redeemed by the Company at any time.
Each share of Preferred Stock is convertible at the option of the holder thereof, at any time, into the number of fully paid and nonassessable shares of common stock equal to the quotient of (1) one hundred dollars ($100.00) divided by (ii) the conversion price applicable to shares of common stock as determined pursuant to the Indenture and in effect at the time of conversion (and any fractional shares will be paid in
cash). As for the 2015 Notes, a holder may not convert all or any portion of such holder’s Preferred Stock into common stock to the extent that such holder and its affiliates would, after giving effect to such conversion beneficially own more than the Maximum Ownership Percentage (as defined in the Indenture governing the 2015 Notes).
During the first quarter of 2011, 36,400 shares of Preferred Stock were converted into 5,766,667 shares of common stock. During March 2012, 8,935 shares of Preferred Stock were converted into 1,489,166 shares of common stock.
Common Stock
The Company had 169,823,681 shares of common stock issued and 73,700 shares held in treasury as of December 31, 2012. The common shareholders are entitled to one vote per share on all matters to be voted on by the shareholders; however, there are no cumulative voting rights. The common shareholders are entitled to dividends and other distributions as may be declared by the board of directors. Upon liquidation or dissolution, the common shareholders will be entitled to share ratably in the distribution of all assets remaining available for distribution after satisfaction of all liabilities and payment of the liquidation preference of any outstanding preferred stock.
As of December 31, 2012, the Company had 9,506,943 shares of common stock issuable upon exercise of outstanding options, 336,000 shares of unvested restricted stock and additional 11,466,640 shares of common stock available for issuance under its long term incentive plan.
As of December 31, 2012, assuming all of the 2015 Notes are converted at the applicable conversion prices and all of the Preferred Stock is converted, the number of shares of our common stock outstanding would increase by approximately 105,624,173 shares of common stock resulting in an increase in the outstanding shares as December 31, 2012 to approximately 275,374,154 shares (this number assumes no exercise of the options described above and no additional grants of options or restricted stock).
The Company’s common stock equity transactions during 2012 and 2011 are described as follows:
On June 15, 2011, the Company closed its underwritten registered offering of 25,000,000 units (the “June Offering”) at a price of $0.24 per unit, for gross proceeds of $6.0 million. Each unit consisted of (i) one share of common stock and (ii) one warrant to purchase 0.75 of a share of common stock. The shares of common stock and June Warrants were issued separately. The net proceeds from the June Offering were $5,108,143, after deducting underwriting discounts and commissions and other offering expenses of $891,857.
On August 3, 2011, the Company closed an underwritten registered offering of 16,000,000 units (the “August Offering” and collectively with the June Offering, the “Offerings”) at a price of $0.25 per unit, for gross proceeds of $4.0 million. Each unit consisted of (i) one share of common stock and (ii) one warrant to purchase 0.71875 of a share of common stock . The shares of common stock and August Warrants were issued separately. The net proceeds from the August Offering were $3,604,910, after deducting underwriting discounts, commissions and other offering expenses of $395,090.
The Warrants are exercisable immediately for a term of sixty months, beginning at issuance, at an initial exercise price of $0.35 per share; however, the exercise price and number of shares of common stock issuable on exercise of the Warrants are subject to adjustment in the event of any stock split, reverse stock split, stock dividend, recapitalization, reorganization or similar transaction. If the Company makes a distribution of its assets to all of its stockholders, holders of the Warrants may be entitled to participate. In the event of a Fundamental Transaction (as defined in the Warrants), at the election of a holder of a
Warrant, the Company may be required to purchase the holder’s Warrant for cash in an amount equal to the value of the remaining unexercised portion of the Warrant. As a result, the Warrants are accounted for as a liability on the Company’s consolidated balance sheet with changes in their fair value reported in earnings. The June Warrants and the August Warrants were recorded at their fair values of $1,850,625 and $2,185,000, respectively, at the issuance dates. Subject to certain exceptions, if the average of the daily volume weighted-average price of a share of common stock for some period of time equals or exceeds 200% of the initial exercise price of the Warrants, and if at the time of such measurement the Equity Conditions (as defined in the Warrants) are satisfied, then the Company may, subject to certain conditions, require the holders of the Warrants to exercise.
During the first quarter of 2012 and 2011, 8,935 and 34,600 shares of Preferred Stock were converted into 1,489,166 and 5,766,667 shares of common stock, respectively.
During the years ended December 31, 2012 and 2011, the Company’s Board of Directors approved the issuance of 250,000 and 75,000 restricted shares of common stock, respectively, to certain of the Company’s employees. The restricted shares vest at varying schedules within three to five years. The shares fully vest upon certain events, such as a change in control of the Company, expiration of the individual’s employment agreement and termination by the Company of the individual’s employment without cause. Any unvested shares are forfeited upon termination of employment for any other reason. The shares of restricted stock are considered issued and outstanding at the date of grant and are included in shares outstanding upon vesting for the purposes of computing diluted earnings per share.
NOTE 13 - STATEMENTS OF CASH FLOWS
During the year ended December 31, 2012, the Company’s non-cash investing and financing activities consisted of the following transactions:
· Conversion of 8,935 shares of Preferred Stock into 1,489,166 shares of common stock.
· Settlement of a $121,000 liability with a prepaid deposit.
· Additions to oil and gas properties included in accounts payable of $454,000.
· Write-off of fully depreciated furniture, fixtures and equipment of $252,424.
During the year ended December 31, 2011, the Company’s non-cash investing and financing activities consisted of the following transactions:
· Recognition of an asset retirement obligation for the plugging and abandonment costs related to the Company’s oil and gas properties valued at $1,405.
· Reduction in stock-based compensation expense of $674 capitalized as proved property.
· Conversion of 34,600 shares of Preferred Stock into 5,766,667 shares of common stock.
· Additions to oil and gas properties included in accounts payable of $830,000.
Cash paid for interest during the years ended December 31, 2012, 2011 and 2010 was $2,598,381, $3,786,641 and $4,095,566, respectively. There was no cash paid for income taxes during the years ended December 31, 2012, 2011 and 2010.
NOTE 14 - INCOME TAXES
The provision (benefit) for income taxes for the years ended December 31, 2012, 2011 and 2010 consists of the following:
A reconciliation of the provision (benefit) for income taxes computed at the statutory rate to the provision for income taxes as shown in the consolidated statements of operations for the years ended December 31, 2012, 2011 and 2010 is summarized below:
The components of the deferred tax assets and liabilities as of December 31, 2012 and 2011 are as follows:
The Company has $54,541,750 of net operating loss carryovers for federal income tax purposes as of December 31, 2012, of which $3,030,233 is not benefited for financial statement purposes as it relates to tax deductions that deviate from compensation expense for financial statement purposes. The benefit of these excess tax deductions will not be recognized for financial statement purposes until the related deductions reduce taxes payable. The Company has $41,063,071 of net operating loss carryovers for state income tax purposes as of December 31, 2012, of which the above excess tax deductions have similarly not been benefited for financial statement purposes. The net operating losses may offset against taxable income through the year ended December 31, 2032. A portion of the net operating loss carryovers begins expiring in 2019. The Company has analyzed the implications of an ownership change pursuant to IRC Section 382 on its net operating losses and has made appropriate adjustments to the federal and state net operating loss carryovers and related deferred tax assets in its financial statements. Such adjustments have no impact on the financial statements as the Company’s deferred tax assets net of liabilities are subject to a full valuation allowance. The Company provided a valuation allowance against its net deferred tax asset of $25,301,485 and $19,803,198 as of December 31, 2012 and 2011, respectively, since it believes that it is more likely than not that the net deferred tax assets will not be fully realized on future income tax returns. The decrease and increase in the valuation allowance for 2012 and 2011 is $5,498,287 and $(55,013,560), respectively.
NOTE 15 - RELATED PARTY TRANSACTIONS
Certain of the Company’s directors and officers have working and/or overriding royalty interests in oil and gas properties in which the Company has an interest. It is expected that the directors and officers may participate with the Company in future projects. All participation by directors and officers will continue to be approved by the disinterested members of the Company’s Board of Directors.
NOTE 16 - COMMITMENTS
The Company leases approximately 11,170 square feet of office space in Denver, Colorado under a lease which terminates on May 31, 2017. The Company’s future rental payments due under this lease are as follows:
Rent expense for the years ended December 31, 2012, 2011 and 2010 was $153,509, $142,090 and $166,334, respectively.
As is customary in the oil and gas industry, the Company may at times have commitments in place to reserve or earn certain acreage positions or wells. If the Company does not pay such commitments, the acreage positions or wells may be lost.
On February 8, 2011, the Company entered into new employment agreements with its two key officers, W. King Grant and Michael K. Decker, which replace in their entirety the employment agreements previously in effect. The agreements were effective January 1, 2011 and the total minimum compensation under the agreements is an aggregate of $590,000 per annum and the initial terms of the agreements will
expire on the second anniversary of the effective date and will automatically renew for additional one-year terms unless either party elects not to renew or the agreements are otherwise terminated in accordance with their terms. These agreements were renewed through January 1, 2014. The agreements contain clauses regarding termination of the officers that could require payment of an amount ranging from 1.5 to two times annual compensation.
During March 2010, per the Base Contract for Sale and Purchase of Natural Gas that the Company has with Anadarko Energy Services Company, dated December 1, 2007, the Company entered into a term sales and transportation transaction to sell up to 50,000 MMBtu per day of its gross production through 2013 from the Uinta Basin. The transaction contains two pricing mechanisms: (1) up to 25,000 MMBtu per day will be priced at the NW Rockies first of month price and (2) up to 25,000 MMBtu per day will be priced at the first of the month index price as published by Gas Daily for the North West Wyoming Poll Index price.
The Company has gathering, processing, and transportation through-put commitments with Monarch, Chipeta and Questar Pipeline Company that require delivery of a fixed determinable quantity of gas production. The aggregate minimum commitment to deliver is 25,000 Mcf of natural gas per day to Monarch for gathering and 25,000 Mcf of natural gas per day to Chipeta for processing. The aggregate minimum commitment is 25,000 MMBtu of natural gas per day to QPC for transportation services. These contracts expire at various dates through 2023 and the Company will be required to make periodic deficiency payments for any shortfalls in delivering the minimum volume commitments. The annual minimum payments for the next five years and thereafter are presented below:
These amounts are owed regardless of whether the Company delivers any natural gas quantities to the applicable parties. As described in Note 2 - Going Concern, herein, there is substantial doubt regarding the Company’s ability to generate sufficient cash flows from operations to fund its ongoing operations. If the Company is unable to fund additional drilling projects, and based on its December 31, 2012 reserve estimates, assuming no future drilling and constant gas prices, it estimates that it could have a possible minimum production shortfall of approximately 54,000 MMcf valued at approximately $37 million on an undiscounted gross basis.
The Company is considering several alternatives to mitigate the estimated production shortfall such as the sale of its firm commitment positions, seeking relief from the firm commitments because of the permitting delays in the area and the purchase of production quantities to meet its minimum production requirements. Also, future increases in gas prices would increase the related reserve estimates and reduce the possible shortfalls. However, there is no assurance that the Company will be successful in accomplishing these actions should there be a shortfall. Accordingly, the Company has not accrued the possible obligation as of December 31, 2012 as it is not probable or reasonably estimable.
NOTE 17 - EMPLOYEE BENEFIT PLANS
The Company adopted a 401(k) profit sharing plan (the “401(k) Plan”) in October 2001 available to employees who meet the 401(k) Plan’s eligibility requirements. The 401(k) Plan is a defined contribution plan. The Company may make discretionary contributions to the 401(k)Plan and is required to contribute 3% of each participating employee’s compensation to the 401(k) Plan. The contributions made by the Company totaled $129,354, $118,573 and $127,169 during the years ended December 31, 2012, 2011 and 2010, respectively.
NOTE 18 - SELECTED QUARTERLY INFORMATION (Unaudited)
The following represents selected quarterly financial information for the years ended December 31, 2012 and 2011. In March 2012, the Company closed the Uinta Basin Transaction whereby the Company sold to Wapiti an undivided 50% of its interest in certain of its Uinta Basin producing oil and gas assets, and transferred to Wapiti an undivided 50% of its interest in its Uinta Basin non-producing oil and gas assets, as further described in Note 4 - Asset Sales and Acquisitions.
(a) The increase in the net loss during the fourth quarter of 2012 is primarily due to a $7,415,000 property impairment recorded during the period.
(b) The increase in net loss and the decrease in gross profit from oil and gas operations during the fourth quarter of 2011 is primarily due to the increase in lease operating expense due to the increased workover activity in 2011.
NOTE 19- LEGAL PROCEEDINGS
The Company is party to various legal proceedings arising out of the normal course of business. The most significant legal proceedings to which the Company is subject are summarized below. The ultimate outcome of the Clean Water Act Compliance Order matter cannot presently be determined, nor can the
liability that could potentially result from an adverse outcome be reasonably estimated at this time. The Company does not expect the outcome of these proceedings to have a material adverse effect on its financial position, results of operations or cash flows.
Clean Water Act Compliance Order Matter
On October 3, 2011, the Company received a compliance order from the United States Environmental Protection Agency (the “EPA”) Region 8 under the authority of the federal Clean Water Act. The compliance order alleges that the Company violated the Clean Water Act by discharging fill material into wetlands adjacent to the Green River in Utah without authorization on two occasions: (i) once when it constructed an access road to a future well location in either 2004 or 2005 and (ii) once when it constructed an access road and a well pad in 2007 or 2008. The compliance order directs the Company to remove all dredged or fill material alleged to have been placed in the wetlands and to restore the wetlands to their pre-impact condition and grade, which would require that the Company plug and abandon the well alleged to have been installed in a wetlands area. The compliance order does not seek any civil penalties for the alleged violations. The Company disagrees with some of the factual contentions in the compliance order, and it has had a number of discussions with the EPA concerning the order. However, it has been unable to negotiate a successful resolution of the alleged violations with the EPA, and as a result, it filed a lawsuit in federal district court in the District of Colorado on June 25, 2012. The lawsuit seeks judicial review of the compliance order, specifically review of the EPA’s contention that the affected areas are wetlands, or if they are wetlands, whether they are wetlands that are subject to federal regulatory jurisdiction under the Clean Water Act. On September 5, 2012, the EPA, represented by the Department of Justice, answered, and the United States separately counterclaimed for an injunction seeking substantially the same relief that the EPA seeks in the compliance order but also requested civil penalties for each day of alleged discharges of fill material and each day of alleged violation of the compliance order. The Company has answered the EPA’s counterclaim. In late January 2013, pursuant to a Scheduling Order before the court, the Company submitted a brief in support of its claims under the original suit filed in June 2012.
NEPA Suit
In June 2012, the BLM signed and issued a Rule of Decision on the EIS that authorizes the development of the Company’s Uinta Basin field upon federal lands in Duchesne and Uintah Counties, Utah. This field includes the Company’s core Riverbend Project. However on January 18, 2013, certain non-governmental environmental organizations, including the Southern Utah Wilderness Alliance, or SUWA, filed a suit against the BLM, challenging the ROD issued by that agency. In its complaint, SUWA alleges that the BLM failed to comply with the requirements of NEPA and its implementing regulations. SUWA was seeking, among other things, that the ROD and EIS be set aside, the effect of which would void the BLM’s authorization for the Company to proceed with its planned project. Only recently, on February 13, 2013, SUWA voluntarily submitted notice of dismissal of the suit to the District Court. Because SUWA voluntarily withdrew its suit, it has the opportunity to refile the suit at a later date. Whether SUWA will refile this suit at a later date is currently unknown to the Company. While any future suit by SUWA or any other third party that seeks to set aside the ROD issued by the BLM for the Company’s planned project in the Uinta Basin field in Utah could, if successfully, have a material adverse effect on the Company’s ability to perform the planned project, the Company would not expect the outcome of such proceeding to have a material adverse effect on the Company’s financial position, results of operations or cash flows.
Hat Creek Settlement
In February 2013, the Company settled a claim with one of its working interest owners, Hat Creek Energy LLC (“Hat Creek”), in connection with a well that was operated by the Company and owned by both parties. Hat Creek filed the claim on April 2, 2012 in the Denver District Court, alleging that Hat Creek did not consent to certain reworking operations performed by the Company in violation of the joint operating agreement, and that Hat Creek’s working interest in the well was impaired as a result. Hat Creek sought damages of not less than $200,000, and the Company sought counterclaim damages for receivables owed by Hat Creek and for the reworking costs. The Company settled this claim for $315,000 consisting of a $160,000 cash payment to Hat Creek and the forgiveness of $155,000 in accounts receivable owed to the Company by Hat Creek. In addition, the settlement provides that the Company will receive Hat Creek’s ownership interest in the well. The final settlement has been accrued in the accompanying consolidated financial statements and is dependent upon the completion of the final settlement documents.
NOTE 20 - GUARANTOR SUBSIDIARIES
On August 31, 2011, the Company filed a Form S-3 shelf registration statement with the SEC, which was declared effective on September 20, 2011. Under this registration statement, the Company may from time to time offer and sell securities including common stock, preferred stock, depositary shares, warrants and debt securities that may be fully, irrevocably and unconditionally guaranteed by all of its subsidiaries: Gasco Production Company, Riverbend Gas Gathering, LLC and Myton Oilfield Rentals, LLC (collectively, the “Guarantor Subsidiaries”). The stand-alone parent entity, Gasco Energy, Inc., has insignificant independent assets and no operations. Therefore, supplemental financial information on a condensed consolidating basis of the Guarantor Subsidiaries is not required. There are no restrictions on the Company’s ability to obtain cash dividends or other distributions of funds from the Guarantor Subsidiaries, except those imposed by applicable law.
NOTE 21 - SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (Unaudited)
The following reserve quantity and future net cash flow information for the Company represents estimated proved reserves located in the United States. The reserves as of December 31, 2012, 2011 and 2010 have been estimated by Netherland, Sewell and Associates, Inc., independent petroleum engineers. The determination of oil and gas reserves is based on estimates, which are highly complex and interpretive. The estimates are subject to continuing change as additional information becomes available.
The standardized measure of discounted future net cash flows is prepared under the guidelines set forth by the Securities and Exchange Commission (the “SEC”) which requires the use of the average, first-of-the-month price. The oil and gas prices weighted by production over the lives of the proved reserves used as of December 31, 2012, 2011 and 2010 were $80.25 per Bbl and $2.15 per Mcf of gas, $81.35 per Bbl and $3.59 per Mcf of gas, and $64.97 per Bbl of oil and $3.62 per Mcf of gas, respectively. Future production costs are based on year-end costs and include severance taxes. Each property that is operated by the Company is also charged with field-level overhead in the reserve calculation. The present value of future cash inflows is based on a 10% discount rate.
Reserve Quantities
(a) Better than anticipated existing well performances related to behind pipe reserves that began producing during both years yielded positive reserve revisions during the years ended December 31, 2011 and 2010.
(b) Downward revisions during the year ended December 31, 2012 are comprised of the following:
Standardized Measure of Discounted Future Net Cash Flows
(a) The calculations of standardized measure do not include deductions for future income tax expenses because the tax basis of the properties involved and the future tax deductions were greater than the net cash flows from the proved oil and gas reserves for the years ended December 31, 2012, 2011 and 2010.
Changes in the Standardized Measure of Discounted Future Net Cash Flows
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
As required by Rule 13a-15(b) under the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, 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 Exchange Act) as of the end of the period covered by this report. Our disclosure controls and procedures are designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and that such information is accumulated and communicated to our management, including our principal executive and principal financial officers or persons performing similar functions, as appropriate to allow such persons to make timely decisions regarding required disclosures.
Based upon the results of our evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective as of December 31, 2012, at the reasonable assurance level.
Changes in Internal Controls over Financial Reporting during the Fourth Quarter of 2012
There have not been any changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934) during our most recently completed fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
In accordance with Item 308 of SEC Regulation S-K, management is required to provide an annual report regarding our internal control over financial reporting. This report, which includes management’s assessment of the effectiveness of our internal control over financial reporting, is found below.
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, under the supervision of the Company’s principal executive and financial officers, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America (“GAAP”). The Company’s internal control over financial reporting includes those policies and procedures that: (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company; (ii) 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 (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on the financial statements.
Because of inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2012. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control-Integrated Framework.
Based on the assessment and those criteria, management has concluded that the Company maintained effective internal control over financial reporting as of December 31, 2012.
The effectiveness of the Company’s internal control over financial reporting as of December 31, 2012 was audited by KPMG LLP, the independent registered public accounting firm who audited the Company’s financial statements for the year ended December 31, 2012, as stated in its report that follows.
Report of Independent Registered Public Accounting Firm
The Board of Directors and Stockholders
Gasco Energy, Inc.:
We have audited Gasco Energy, Inc.’s (the Company) internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of the Company and subsidiaries as of December 31, 2012 and 2011, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2012, and our report dated March 6, 2013 expressed an unqualified opinion on those consolidated financial statements.
The consolidated financial statements referred to above have been prepared assuming that the Company will continue as a going concern. As discussed in note 2 to the consolidated financial statements, the Company has suffered recurring losses and negative cash flows from operations that raise 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 consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.
/s/ KPMG LLP
Denver, Colorado
March 6, 2013
ITEM 9B
ITEM 9B - OTHER INFORMATION
None.
PART III
ITEM 10
ITEM 10 - DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
The information required by this item will be included in the definitive proxy statement relating to the Company’s 2013 Annual Meeting of Shareholders to be filed with the SEC pursuant to Regulation 14A, which information is incorporated herein by reference.
The Board of Directors of the Company has adopted several governance documents to guide the operation and direction of the Board and its committees, including our Corporate Code of Business Conduct and Ethics, Financial Code of Ethics, and charters for the Audit Committee, Compensation Committee and Nominating Committee. Each of these documents is available on our website at www.gascoenergy.com and stockholders may obtain a printed copy, free of charge, by sending a written request to Gasco Energy, Inc., 8 Inverness Drive East, Suite 100, Englewood, Colorado 80112, Attn: Corporate Secretary. To the extent required by SEC rules, we intend to disclose any amendments to Corporate Code of Business Conduct and Ethics and any waiver of a provision thereof, on our website within four business days following any such amendment or waiver, or within any other period that may be required under SEC rules from time to time.
ITEM 11
ITEM 11 - EXECUTIVE COMPENSATION
The information required by this item will be included in the definitive proxy statement relating to the Company’s 2013 Annual Meeting of Shareholders to be filed with the SEC pursuant to Regulation 14A, which information is incorporated herein by reference.
ITEM 12
ITEM 12 - SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
The information required by this item will be included in the definitive proxy statement relating to the Company’s 2013 Annual Meeting of Shareholders to be filed with the SEC pursuant to Regulation 14A, which information is incorporated herein by reference.
ITEM 13
ITEM 13 - CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
The information required by this item will be included in the definitive proxy statement relating to the Company’s 2013 Annual Meeting of Shareholders to be filed with the SEC pursuant to Regulation 14A, which information is incorporated herein by reference.
ITEM 14
ITEM 14 - PRINCIPAL ACCOUNTING FEES AND SERVICES
The information required by this item will be included in the definitive proxy statement relating to the Company’s 2013 Annual Meeting of Shareholders to be filed with the SEC pursuant to Regulation 14A, which information is incorporated herein by reference.
PART IV
ITEM 15
ITEM 15 - EXHIBITS, FINANCIAL STATEMENT SCHEDULES
The following is a list of exhibits filed or furnished (as indicated) as part of this Annual Report on Form 10-K. Where so noted, exhibits which were previously filed are incorporated herein by reference.
(a)
1. See “Index to Financial Statements” under Item 8 on page 80.
2. Financial Statement Schedules - none.
3. Exhibits - See Index to Exhibits, below.
INDEX TO EXHIBITS
3.1
Restated and Amended Articles of Incorporation (incorporated herein by reference to Exhibit 3.1 to the Company’s Form 8-K dated December 31, 1999, filed on January 21, 2000, File No. 000-26321).
3.2
Certificate of Amendment to Articles of Incorporation (incorporated herein by reference to Exhibit 3.1 to the Company’s Form 8-K/A dated January 31, 2001, filed on February 16, 2001, File No. 000-26321).
3.3
Certificate of Amendment to Articles of Incorporation dated June 21, 2005 (incorporated herein by reference to Exhibit 3.3 to the Company’s Form 10-Q/A for the quarter ended June 30, 2005, filed on August 9, 2005, File No. 001-32369).
3.4
Certificate of Amendment to Articles of Incorporation dated September 20, 2010 (incorporated herein by reference to Exhibit 3.1 to the Company’s Form 8-K dated September 15, 2010, filed on September 20, 2010, File No. 001-32369).
3.5
Second Amended and Restated Bylaws of Gasco Energy, Inc. dated April 8, 2009 (incorporated herein by reference to Exhibit 3.1 to the Company’s Form 8-K dated April 8, 2009, filed on April 8, 2009, File No. 001-32369).
3.6
Certificate of Designations, Preferences and Rights of Series B Convertible Preferred Stock (incorporated herein by reference to Exhibit 3.5 to the Company’s Form S-1 Registration Statement dated April 16, 2003, filed April 17, 2003, File No. 333-104592).
3.7
Certificate of Designation for Series C Convertible Preferred Stock dated as of June 22, 2010 (incorporated herein by reference to Exhibit 3.1 to the Company’s Form 8-K dated June 22, 2010, filed on June 28, 2010, File No. 001-32369).
4.1
Indenture (including form of 2015 Note) dated as of June 25, 2010 between Gasco Energy, Inc. and Wells Fargo Bank, National Association (incorporated herein by reference to Exhibit 4.1 to the Company’s Form 8-K dated June 22, 2010, filed on June 28, 2010, File No. 001-32369).
4.2
First Supplemental Indenture dated as of September 22, 2010 between Gasco Energy, Inc. and Wells Fargo Bank, National Association (incorporated herein by reference to Exhibit 10.7 to the Company’s Form 10-Q dated September 30, 2010, filed on November 2, 2010, File No. 001-32369).
4.3
Guaranty Agreement dated as of June 25, 2010 among Gasco Production Company, Riverbend Gas Gathering, LLC, and Myton Oilfield Rentals, LLC, in favor of Wells Fargo Bank, National Association (incorporated herein by reference to Exhibit 4.2 to the Company’s Form 8-K dated June 22, 2010, filed on June 28, 2010, File No. 001-32369).
4.4
Investor Rights Agreement dated as of June 25, 2010 among Gasco Energy, Inc., CNH CA Master Account, L.P. and AQR Absolute Return Master Account, L.P. (incorporated herein by reference to Exhibit 4.3 to the Company’s Form 8-K dated June 22, 2010, filed on June 28, 2010, File No. 001-32369).
4.5
Form of Warrant (incorporated herein by reference to Exhibit 4.1 to the Company’s Form 8-K dated June 10, 2011, filed on June 10, 2011, File No. 001-32369).
4.6
Form of Warrant (incorporated herein by reference to Exhibit 4.2 to the Company’s Form 8-K dated July 28, 2011, filed on July 29, 2011, File No. 001-32369).
# 10.1
1999 Stock Option Plan (incorporated herein by reference to Exhibit 4.1 to the Company’s Form 10KSB for the fiscal year ended December 31, 1999, filed on April 14, 2000, File No. 000-26321).
# 10.2
Form of Stock Option Agreement under the 1999 Stock Option Plan (incorporated herein by reference to Exhibit 10.8 to the Company’s Form 10-K for the fiscal year ended December 31, 2001, filed on March 29, 2002, File No. 000-26321).
# 10.3
Stock Option Agreement dated January 2, 2001 between Gasco and Mark A. Erickson (incorporated herein by reference to Exhibit 10.9 to the Company’s Form 10-K for the fiscal year ended December 31, 2001, filed on March 29, 2002, File No. 000-26321).
# 10.4
Form of Stock Option Agreement between Gasco and each of the individuals named therein (incorporated herein by reference to Exhibit 4.4 to the Company’s Form S-8 Registration Statement (Reg. No. 333-122716), filed on February 10, 2005).
# 10.5
2003 Restricted Stock Plan (incorporated herein by reference to Appendix B to the Company’s Proxy Statement dated August 25, 2003 for its 2003 Annual Meeting of Stockholders, filed on August 25, 2003, File No. 000-26321).
#10.6
Form of Amendment to Gasco Energy, Inc. Employment Agreement dated as of December 31, 2008, and effective as of January 1, 2009, by and among Gasco Energy, Inc. and certain of its Executives (incorporated herein by reference to Exhibit 10.1 to the Company’s Form 8-K dated December 31, 2008, filed January 7, 2009, File No. 001-32369).
#10.7
Form of Second Amendment to Gasco Energy, Inc. Employment Agreement dated and effective as of January 22, 2009, by and among Gasco Energy, Inc. and certain of its Executives (incorporated herein by reference to Exhibit 10.12 to the Company’s Form 10-K for the fiscal year ended December 31, 2008, filed on March 4, 2009, File No. 001-32369).
10.8
Form of Exchange Agreement dated as of June 22, 2010 between Gasco Energy, Inc. and each of the Investors (incorporated herein by reference to Exhibit 10.1 to the Company’s Form 8-K dated June 22, 2010, filed on June 28, 2010, File No. 001-32369).
#10.9
Employment Agreement entered into by and between Gasco Energy, Inc. and W. King Grant, effective as of February 8, 2011 (incorporated herein by reference to Exhibit 10.1 to the Company’s Form 8-K dated February 8, 2011, filed on February 11, 2011, File No. 001-32369).
#10.10
Employment Agreement entered into by and between Gasco Energy, Inc. and Michael K. Decker, effective as of February 8, 2011 (incorporated herein by reference to Exhibit 10.2 to the Company’s Form 8-K dated February 8, 2011, filed on February 11, 2011, File No. 001-32369).
#10.11
Gasco Energy, Inc. 2011 Long Term Incentive Plan (incorporated herein by reference to Exhibit 10.1 to the Company’s Form 10-Q dated June 30, 2011, filed on August 9, 2011, File No. 001-32369).
10.12
Gas Processing Agreement dated September 21, 2011 by and between Gasco Energy, Inc. and Chipeta Processing LLC (incorporated herein by reference to Exhibit 10.1 to the Company’s Form 8-K dated September 20, 2011, filed on September 26, 2011, File No. 001-32369).
10.13
Amended and Restated Gas Gathering and Processing Agreement dated March 22, 2012, by and between Gasco Production Company and Monarch Natural Gas, LLC (incorporated herein by reference to Exhibit 10.1 to the Company’s Form 8-K dated March 22, 2012, filed on March 28, 2012, File No. 000-26321).
#10.14
Form of Stock Appreciation Right Agreement (incorporated herein by reference to Exhibit 10.4 to the Company’s Form 10-Q dated September 30, 2011, filed on November 1, 2011, File No. 001-32369).
10.15
Purchase and Sale Agreement dated February 23, 2012, by and among Gasco Production Company and Wapiti Oil & Gas II, L.L.C. (incorporated herein by reference to Exhibit 2.1 to the Company’s Form 8-K dated March 22, 2012, filed on March 28, 2012, File No. 000-26321).
10.16
Development Agreement dated March 22, 2012, between Gasco Production Company and Wapiti Oil & Gas II, L.L.C. (incorporated herein by reference to Exhibit 2.2 to the Company’s Form 8-K dated March 22, 2012, filed on March 28, 2012, File No. 000-26321).
10.17
Closing Agreement dated March 22, 2012, by and among Gasco Production Company and Wapiti Oil & Gas II, L.L.C. (incorporated herein by reference to Exhibit 2.3 to the Company’s Form 8-K dated March 22, 2012, filed on March 28, 2012, File No. 000-26321).
#10.18
Form of Stock Appreciation Right Agreement (incorporated herein by reference to Exhibit 10.35 to the Company’s Form 10-K, dated December 31, 2011, filed on March 28, 2012, File No. 001-32369).
* 10.19
Amendment to Gas Processing Agreement dated December 1, 2013, by and between Chipeta Processing LLC and Gasco Energy, Inc.
*21.1
Subsidiaries of Gasco Energy, Inc.
*23.1
Consent of Netherland, Sewell & Associates, Inc., independent petroleum engineers and geologists
*23.2
Consent of KPMG LLP
*31.1
Rule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer
*31.2
Rule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer
**32.1
Section 1350 Certification of Principal Executive Officer
**32.2
Section 1350 Certification of Principal Financial Officer
*99.1
Report of Netherland, Sewell & Associates, Inc., independent petroleum engineers and geologists
***101.INS
XBRL Instance Document
***101.SCH
XBRL Schema Document
***101.CAL
XBRL Calculation Linkbase Document
***101.LAB
XBRL Label Linkbase Document
***101.PRE
XBRL Presentation Linkbase Document
***101.DEF
XBRL Taxonomy Extension Definition Linkbase Document
* Filed herewith.
** Furnished herewith.
*** Furnished, not filed. Users of this data submitted electronically herewith are advised pursuant to Rule 406T of Regulation S-T that this interactive data file is deemed not filed or part of a registration statement or prospectus for purposes of sections 11 or 12 of the Securities Act of 1933, is deemed not filed for purposes of Section 18 of the Securities Exchange Act of 1934, and otherwise is not subject to liability under these sections.
# Identifies management contracts and compensatory plans or arrangements.
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.
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/ Charles B. Crowell
Director
March 6, 2013
Charles B. Crowell
/s/ Richard S. Langdon
Director
March 6, 2013
Richard S. Langdon
/s/ R. J. Burgess
Director
March 6, 2013
R.J. Burgess
/s/ John A. Schmit
Director
March 6, 2013
John A. Schmit
/s/ Steven D. (Dean) Furbush
Director
March 6, 2013
Steven D. (Dean) Furbush
/s/ W. King Grant
President, Chief Executive Officer and Director
March 6, 2012
W. King Grant
(Principal Executive Officer)
/s/ Peggy A. Herald
Vice President and Chief Accounting Officer
March 6, 2013
Peggy A. Herald
(Principal Financial Officer)
INDEX TO EXHIBITS
3.1
Restated and Amended Articles of Incorporation (incorporated herein by reference to Exhibit 3.1 to the Company’s Form 8-K dated December 31, 1999, filed on January 21, 2000, File No. 000-26321).
3.2
Certificate of Amendment to Articles of Incorporation (incorporated herein by reference to Exhibit 3.1 to the Company’s Form 8-K/A dated January 31, 2001, filed on February 16, 2001, File No. 000-26321).
3.3
Certificate of Amendment to Articles of Incorporation dated June 21, 2005 (incorporated herein by reference to Exhibit 3.3 to the Company’s Form 10-Q/A for the quarter ended June 30, 2005, filed on August 9, 2005, File No. 001-32369).
3.4
Certificate of Amendment to Articles of Incorporation dated September 20, 2010 (incorporated herein by reference to Exhibit 3.1 to the Company’s Form 8-K dated September 15, 2010, filed on September 20, 2010, File No. 001-32369).
3.5
Second Amended and Restated Bylaws of Gasco Energy, Inc. dated April 8, 2009 (incorporated herein by reference to Exhibit 3.1 to the Company’s Form 8-K dated April 8, 2009, filed on April 8, 2009, File No. 001-32369).
3.6
Certificate of Designations, Preferences and Rights of Series B Convertible Preferred Stock (incorporated herein by reference to Exhibit 3.5 to the Company’s Form S-1 Registration Statement dated April 16, 2003, filed April 17, 2003, File No. 333-104592).
3.7
Certificate of Designation for Series C Convertible Preferred Stock dated as of June 22, 2010 (incorporated herein by reference to Exhibit 3.1 to the Company’s Form 8-K dated June 22, 2010, filed on June 28, 2010, File No. 001-32369).
4.1
Indenture (including form of 2015 Note) dated as of June 25, 2010 between Gasco Energy, Inc. and Wells Fargo Bank, National Association (incorporated herein by reference to Exhibit 4.1 to the Company’s Form 8-K dated June 22, 2010, filed on June 28, 2010, File No. 001-32369).
4.2
First Supplemental Indenture dated as of September 22, 2010 between Gasco Energy, Inc. and Wells Fargo Bank, National Association (incorporated herein by reference to Exhibit 10.7 to the Company’s Form 10-Q dated September 30, 2010, filed on November 2, 2010, File No. 001-32369).
4.3
Guaranty Agreement dated as of June 25, 2010 among Gasco Production Company, Riverbend Gas Gathering, LLC, and Myton Oilfield Rentals, LLC, in favor of Wells Fargo Bank, National Association (incorporated herein by reference to Exhibit 4.2 to the Company’s Form 8-K dated June 22, 2010, filed on June 28, 2010, File No. 001-32369).
4.4
Investor Rights Agreement dated as of June 25, 2010 among Gasco Energy, Inc., CNH CA Master Account, L.P. and AQR Absolute Return Master Account, L.P. (incorporated herein by reference to Exhibit 4.3 to the Company’s Form 8-K dated June 22, 2010, filed on June 28, 2010, File No. 001-32369).
4.5
Form of Warrant (incorporated herein by reference to Exhibit 4.1 to the Company’s Form 8-K dated June 10, 2011, filed on June 10, 2011, File No. 001-32369).
4.6
Form of Warrant (incorporated herein by reference to Exhibit 4.2 to the Company’s Form 8-K dated July 28, 2011, filed on July 29, 2011, File No. 001-32369).
# 10.1
1999 Stock Option Plan (incorporated herein by reference to Exhibit 4.1 to the Company’s Form 10KSB for the fiscal year ended December 31, 1999, filed on April 14, 2000, File No. 000-26321).
# 10.2
Form of Stock Option Agreement under the 1999 Stock Option Plan (incorporated herein by reference to Exhibit 10.8 to the Company’s Form 10-K for the fiscal year ended December 31, 2001, filed on March 29, 2002, File No. 000-26321).
# 10.3
Stock Option Agreement dated January 2, 2001 between Gasco and Mark A. Erickson (incorporated herein by reference to Exhibit 10.9 to the Company’s Form 10-K for the fiscal year ended December 31, 2001, filed on March 29, 2002, File No. 000-26321).
# 10.4
Form of Stock Option Agreement between Gasco and each of the individuals named therein (incorporated herein by reference to Exhibit 4.4 to the Company’s Form S-8 Registration Statement (Reg. No. 333-122716), filed on February 10, 2005).
# 10.5
2003 Restricted Stock Plan (incorporated herein by reference to Appendix B to the Company’s Proxy Statement dated August 25, 2003 for its 2003 Annual Meeting of Stockholders, filed on August 25, 2003, File No. 000-26321).
#10.6
Form of Amendment to Gasco Energy, Inc. Employment Agreement, dated as of December 31, 2008, and effective as of January 1, 2009, by and among Gasco Energy, Inc. and certain of its Executives (incorporated herein by reference to Exhibit 10.1 to the Company’s Form 8-K dated December 31, 2008, filed January 7, 2009, File No. 001-32369).
#10.7
Form of Second Amendment to Gasco Energy, Inc. Employment Agreement, dated and effective as of January 22, 2009, by and among Gasco Energy, Inc. and certain of its Executives (incorporated herein by reference to Exhibit 10.12 to the Company’s Form 10-K for the fiscal year ended December 31, 2008, filed on March 4, 2009, File No. 001-32369).
10.8
Form of Exchange Agreement dated as of June 22, 2010 between Gasco Energy, Inc. and each of the Investors (incorporated herein by reference to Exhibit 10.1 to the Company’s Form 8-K dated June 22, 2010, filed on June 28, 2010, File No. 001-32369).
#10.9
Employment Agreement entered into by and between Gasco Energy, Inc. and W. King Grant, effective as of February 8, 2011 (incorporated herein by reference to Exhibit 10.1 to the Company’s Form 8-K dated February 8, 2011, filed on February 11, 2011, File No. 001-32369).
#10.10
Employment Agreement entered into by and between Gasco Energy, Inc. and Michael K. Decker, effective as of February 8, 2011 (incorporated herein by reference to Exhibit 10.2 to the Company’s Form 8-K dated February 8, 2011, filed on February 11, 2011, File No. 001-32369).
#10.11
Gasco Energy, Inc. 2011 Long Term Incentive Plan (incorporated herein by reference to Exhibit 10.1 to the Company’s Form 10-Q dated June 30, 2011, filed on August 9, 2011, File No. 001-32369).
10.12
Gas Processing Agreement dated September 21, 2011 by and between Gasco Energy, Inc. and Chipeta Processing LLC (incorporated herein by reference to Exhibit 10.1 to the Company’s Form 8-K dated September 20, 2011, filed on September 26, 2011, File No. 001-32369).
10.13
Amended and Restated Gas Gathering and Processing Agreement dated March 22, 2012, by and between Gasco Production Company and Monarch Natural Gas, LLC (incorporated herein by reference to Exhibit 10.1 to the Company’s Form 8-K dated March 22, 2012, filed on March 28, 2012, File No. 000-26321).
#10.14
Form of Stock Appreciation Right Agreement (incorporated herein by reference to Exhibit 10.4 to the Company’s Form 10-Q dated September 30, 2011, filed on November 1, 2011, File No. 001-32369).
10.15
Purchase and Sale Agreement dated February 23, 2012, by and among Gasco Production Company and Wapiti Oil & Gas II, L.L.C. (incorporated herein by reference to Exhibit 2.1 to the Company’s Form 8-K dated March 22, 2012, filed on March 28, 2012, File No. 000-26321).
10.16
Development Agreement dated March 22, 2012, between Gasco Production Company and Wapiti Oil & Gas II, L.L.C. (incorporated herein by reference to Exhibit 2.2 to the Company’s Form 8-K dated March 22, 2012, filed on March 28, 2012, File No. 000-26321).
10.17
Closing Agreement dated March 22, 2012, by and among Gasco Production Company and Wapiti Oil & Gas II, L.L.C. (incorporated herein by reference to Exhibit 2.3 to the Company’s Form 8-K dated March 22, 2012, filed on March 28, 2012, File No. 000-26321).
#10.18
Form of Stock Appreciation Right Agreement (incorporated herein by reference to Exhibit 10.35 to the Company’s Form 10-K, dated December 31, 2011, filed on March 28, 2012, File No. 001-32369).
* 10.19
Amendment to Gas Processing Agreement dated December 1, 2013, by and between Chipeta Processing LLC and Gasco Energy, Inc.
*21.1
Subsidiaries of Gasco Energy, Inc.
*23.1
Consent of Netherland, Sewell & Associates, Inc., independent petroleum engineers and geologists.
*23.2
Consent of KPMG LLC
*31.1
Rule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer
*31.2
Rule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer
**32.1
Section 1350 Certification of Principal Executive Officer
**32.2
Section 1350 Certification of Principal Financial Officer
*99.1
Report of Netherland, Sewell & Associates, Inc., independent petroleum engineers and geologists.
***101.INS
XBRL Instance Document
***101.SCH
XBRL Schema Document
***101.CAL
XBRL Calculation Linkbase Document
***101.LAB
XBRL Label Linkbase Document
***101.PRE
XBRL Presentation Linkbase Document
***101.DEF
XBRL Taxonomy Extension Definition Linkbase Document
* Filed herewith.
** Furnished herewith.
*** Furnished, not filed. Users of this data submitted electronically herewith are advised pursuant to Rule 406T of Regulation S-T that this interactive data file is deemed not filed or part of a registration statement or prospectus for purposes of sections 11 or 12 of the Securities Act of 1933, is deemed not filed for purposes of Section 18 of the Securities Exchange Act of 1934, and otherwise is not subject to liability under these sections.
# Identifies management contracts and compensatory plans or arrangements.