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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-K/A

 

Amendment No. 1

For the fiscal year ended December 31, 2013

For the transition period from              to             

Commission File No. 1-33571

 

ESCALERA RESOURCES CO.

(Exact name of registrant as specified in its charter)

 

 

1675 Broadway, Suite 2200, Denver, CO 80202

(Address of principal executive offices) (Zip Code)

(303) 794-8445

(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act: None.

Securities registered pursuant to Section 12(g) of the Act:

 

 

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes  ¨    No  x

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    Yes  ¨     No  x

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  x    No  ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  x    No  ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405), is not contained herein, and will not be contained to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  ¨

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

 

Indicate by check mark whether the registrant is a shell company (as defined by Rule 12b-2 in the Act).    Yes  ¨    No  x

The aggregate market value of the voting common stock held by non-affiliates of the registrant at the close of business on June 28, 2013, was $43,263,340 (directors and officers are considered affiliates).

The number of shares of the registrant’s common stock outstanding as of March 7, 2014 was 11,693,130.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant’s definitive proxy statement for the 2014 annual meeting of stockholders, which was filed on April 29, 2014, are incorporated by reference in Part III of this Form 10-K/A.

 

 

 

 

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DOUBLE EAGLE PETROLEUM CO.

FORM 10-K

TABLE OF CONTENTS

 

 

 

 

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Cautionary Information About Forward-Looking Statements

This Form 10-K/A includes “forward-looking statements” as defined by the Securities and Exchange Commission, or SEC. We make these forward-looking statements in reliance on the safe harbor protections provided under Section 27A of the Securities Act of 1933, as amended, Section 21E of the Securities Exchange Act of 1934, as amended, and the Private Securities Litigation Reform Act of 1995. All statements, other than statements of historical facts, included in this Form 10-K that address activities, events or developments that we expect, believe or anticipate will or may occur in the future are forward-looking statements. These forward-looking statements are based on assumptions which we believe are reasonable based on current expectations and projections about future events and industry conditions and trends affecting our business. However, whether actual results and developments will conform to our expectations and predictions is subject to a number of risks and uncertainties that, among other things, could cause actual results to differ materially from those contained in the forward-looking statements, including without limitation the Risk Factors set forth in this Form 10-K/A in Part I, “Item 1A. Risk Factors” and the following factors:

We may also make material acquisitions or divestitures or enter into financing or other transactions. None of these events can be predicted with certainty and the possibility of their occurring is not taken into consideration in the forward-looking statements.

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New factors that could cause actual results to differ materially from those described in forward-looking statements emerge from time to time, and it is not possible for us to predict all such factors, or the extent to which any such factor or combination of factors may cause actual results to differ from those contained in any forward-looking statement. We assume no obligation to update publicly any such forward-looking statements, whether as a result of new information, future events, or otherwise.

The terms “Double Eagle,” the “Company,” “we,” “our,” and “us” refer to Double Eagle Petroleum Co. and its subsidiaries, as a consolidated entity, unless the context suggests otherwise. We have included technical terms important to an understanding of our business under “Glossary”, in Items 1 and 2 “Business and Properties” of this Annual Report on Form 10-K/A for the year ended December 31, 2013. Dollar amounts set forth herein are in thousands unless otherwise noted.

 

EXPLANATORY NOTE

 

This Form 10-K/A (this “Amendment”) amends Escalera Resources Co.’s (formerly Double Eagle Petroleum Co.) (the “Company”) Annual Report on Form 10-K for the Year Ended December 31, 2013 (the “Original 10-K”), which was filed with the Securities and Exchange Commission (the “Commission”) on March 13, 2014.  The Company is amending the Original 10-K to:

 

This Amendment speaks as of the original filing date of the Original 10-K and reflects only the changes to the Original 10-K described above. No other information included in the Original 10-K has been modified or updated, and the Company has not updated the disclosures contained herein to reflect any events which occurred subsequent to the filing of the Original 10-K or to modify the disclosure contained in the Original 10-K other than to reflect the changes described above.

 

The Company also has included as exhibits to this Amendment the certifications required under Sections 302 and 906 of the Sarbanes-Oxley Act of 2002.

 

This Amendment should be read in conjunction with the Company’s filings with the Commission made subsequent to March 13, 2014, the date of the original filing of the Original 10-K.

 

 

PART I

 

ITEMS 1. AND 2. BUSINESS AND PROPERTIES

General

We are an independent energy company engaged in the exploration, development, production and sale of natural gas and crude oil, primarily in the Rocky Mountain basins of the western United States. We were incorporated in Wyoming in 1972 and reincorporated in Maryland in 2001. Our common stock is publicly traded on the NASDAQ Global Select Market under the symbol “DBLE” and our Series A Cumulative Preferred Stock is traded on the NASDAQ Global Select Market under the symbol “DBLEP”. Our corporate offices are located at 1675 Broadway, Suite 2200, Denver, Colorado 80202, telephone number (303) 794-8445. Our website is www.dble.com.

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Overview and Strategy

Our objective is to increase long-term shareholder value by profitably growing our reserves, production, revenues, and cash flow. To meet this objective, we primarily focus on:

Our current production primarily consists of natural gas from two core properties located in southwestern Wyoming. We have coalbed methane (“CBM”) reserves and production in the Atlantic Rim Area of the eastern Washakie Basin and tight gas reserves, and production on the Pinedale Anticline in the Green River Basin of Wyoming. Substantially all of our revenues are generated through the sale of natural gas and oil production at market prices and the settlement of commodity hedges.  We also hold acreage with exploration potential in the Greater Green River Basin of Wyoming and the Huntington Basin of Nevada.  Approximately 98% of our 2013 production volume was natural gas.

As of December 31, 2013, we had estimated proved reserves of 72.8 Bcf of natural gas and 314 MBbl of oil, or a total of 74.7 Bcfe. Of these estimated proved reserves, 80% were proved developed and 97% were natural gas.  As compared to our 2012 year-end reserve estimate, our 2013 year-end reserve estimate decreased by 3.4 Bcfe after reductions for 2013 production, offset in part by increases resulting from extensions and discoveries and revision of estimates.  We had net positive revisions of 4.2 Bcfe which resulted from an increase of 43.9 Bcfe due to pricing revisions, offset in part by decreases resulting from technical revisions of 39.7 Bcfe.   The natural gas prices used in the reserve estimate, as calculated in accordance with the Securities and Exchange Commission’s (“SEC”) pricing rules increased 38% from $2.56 per MMbtu for the year ended December 31, 2012, to $3.53 per MMbtu for the year ended December 31, 2013.  As a result of the higher pricing, certain of our undeveloped well locations on the Pinedale Anticline, which were excluded from our 2012 estimate, became economic.   The negative technical revisions were made to reflect the well performance of its Atlantic Rim properties in 2012 and 2013.  Our 2013 net production totaled 9.2 Bcfe.  

The proved oil and gas reserves at December 31, 2013 had a PV-10 value of approximately $78.2 million, an increase of 34% from December 31, 2012, which was primarily due to the increase in pricing, as noted above. The benefit realized from the increase in pricing was partially offset by a shift in the decline curve at our non-operated Atlantic Rim properties, which reduced the present value of the reserves.  (See the reconciliation of the PV-10 non-GAAP financial measure to the standardized measure under Reserves on page 8).

We developed our 2013 capital spending program so that it would be funded entirely by our estimated cash flow from operations for 2013.  During 2013, we invested $9.6 million in capital expenditures related to the exploration and development of our existing properties, as compared to $23.3 million in 2012.  Our 2013 capital spending program included a well workover program at the Catalina Unit, where we opened-up previously unfractured formations in existing wells, as well as continued participation in non-operated drilling programs.  The operator of the Spyglass Hill Unit drilled and completed 27 new wells, and the operator of the Mesa “B” participating area on the Pinedale Anticline completed 11 of its final 12 well locations in 2013.  

We continually assess projects that are in progress and those proposed for future development to determine the best use for our available capital. This assessment includes analyzing the risk and estimated return for each proposed project, including our non-operated assets (primarily the Pinedale Anticline and the Spyglass Hill Unit in the Atlantic Rim). We expect to invest up to $6 million into capital projects in 2014, primarily for participation in 48 new wells in the Spyglass Hill Unit.  We also continue to evaluate acquisition and merger opportunities that we believe will complement our existing operations, offer economies of scale and/or provide further development, exploitation and exploration opportunities. In addition to potential acquisitions, we also may decide to divest certain non-core assets, enter into strategic partnerships or form joint ventures related to our assets that are not currently considered in our expected 2013 capital expenditures.

Properties and Operations

As of December 31, 2013, we owned interests in over 1,200 producing wells and had an acreage position of 372,815 gross (115,594 net) acres, of which 300,327 gross (100,852 net) acres are undeveloped, in what we believe are natural gas prone basins primarily located in the Rocky Mountains. Two developing areas, the Atlantic Rim coalbed natural gas play and the Pinedale Anticline, accounted for 92% of our proved reserves as of December 31, 2013, and 94% of our 2013 production.

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As of December 31, 2013, our total estimated acreage holdings by basin are:

 

Our project development focus is in areas where we believe our core competencies can provide us with competitive advantages. We intend to grow our reserves and production primarily through our current areas of development, which are as follows:

The Atlantic Rim Coalbed Natural Gas Project

Located in Carbon County of south central Wyoming, the Atlantic Rim play is a 40-mile long trend in the eastern Washakie Basin, in which we have an interest in 95,269 gross (31,030 net) acres. The Mesaverde formation coals in this area differ from those found in the Powder River Basin in that they are thinner zones, but generally have higher gas content. The productivity of coalbeds is dependent not only on specific natural gas content, but also on favorable permeability to natural gas. The primary areas currently being developed within the Atlantic Rim are the Catalina Unit, for which we are the operator, and our non-operated interests in the Spyglass Hill Unit.

In May 2007, a Record of Decision on the Atlantic Rim Environmental Impact Statement (“EIS”) was issued. The EIS allows for the drilling of up to 1,800 CBM wells and 200 conventional oil and gas wells in the Atlantic Rim area, of which 268 of the potential well sites are in the Catalina Unit.

During 2013, we recognized net sales volumes from the coalbed natural gas projects in the Atlantic Rim of 6.9 Bcfe, which represented 75% of our total 2013 natural gas equivalent sales volume. The wells have historically been economic, even in periods of low gas prices, and we intend to continue to focus our efforts to develop and enhance wells in this area.

The Atlantic Rim properties operate under federal unit agreements between the working interest partners. Unitization is a type of sharing arrangement by which owners of operating and non-operating working interests pool their property interests in a producing area to form a single operating unit. Units are designed to improve efficiency and economics of developing and producing an area. The share that each interest owner receives is based upon the percentage of respective acreage contributed by each owner in the participating area (“PA”) surrounding the producing wells in relation to the entire acreage of the PA. The PA, and the associated working interest, may change as more wells and acreage are added to the PA.

Catalina Unit

The Catalina Unit consists of approximately 21,500 gross (13,300 net) acres that we operate. Our development of the Catalina Unit began in 2007 with the 14 original producing wells in the Cow Creek Field and has expanded to 83 production wells as of December 31, 2013.  Our Catalina wells are located in two separate PAs; PA “A” consists of 71 wells in which we have an 85.53% interest and PA “B” consists of 12 wells in which we have a 100% working interest.  As we continue to expand the Catalina Unit PA, our working interest will continue to change. We anticipate our working interest will be approximately 61% upon the completion of planned development of the existing acreage.

Prior to 2011, we drilled the wells in the Catalina Unit using 80 acre spacing. Our historical production results and reservoir studies show that wells drilled in this area on the 80 acre spacing are communicating with each other, which may indicate that by increasing the spacing, we can potentially exploit the same reserves with fewer wells, reducing the necessary capital expenditures. Based on these studies, the 12 wells drilled in 2011 located within PA “B” of the Catalina Unit were drilled on 160 acre spacing.

Production in the Catalina Unit resulted in net sales volumes of 4.9 Bcf in 2013, which represented 54% of our total sales volumes for 2013. During 2013, our average daily net production at the Catalina Unit was 13,516 Mcf.

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CBM gas wells involve removing gas trapped within the coal itself. Often, the coals are completely saturated with water. As water is removed, gas is able to flow to the wellbore. In the Atlantic Rim, we and Warren Resources, Inc. (“Warren”) as operators have received permits by which produced water can be injected back into the ground through injection wells. In 2008, we were granted a permit by the Bureau of Land Management (“BLM”) to treat water removed from the wells, for release on the surface. We are currently the only company in the Atlantic Rim area with such a permit. However, due to the current water production volumes and the cost of water treatment, all of the water produced by our CBM wells is reinjected into the ground.

Eastern Washakie Midstream Pipeline LLC

Through a wholly-owned subsidiary, Eastern Washakie Midstream Pipeline LLC (“EWM”), we own a 13-mile pipeline and gathering assets (“EWM Pipeline”), which connect the Catalina Unit with the pipeline system owned by Southern Star Central Gas Pipeline, Inc. (“Southern Star”). The EWM Pipeline provides us with access to the interstate gas markets, and the ability to move third party gas. We have an agreement in place for transportation and gathering of all Catalina Unit production volumes that move through the EWM Pipeline, for which we receive a fee per Mcf of gas transported. The EWM Pipeline has a transportation capacity of approximately 125 MMcf per day with current volumes representing approximately 20% of capacity. The EWM Pipeline is expected to provide reliable transportation for future development by us and other operators in the Atlantic Rim. EWM also owns survey and right of way permits for a potential extension to the Wyoming Interstate Company interstate pipeline.

In 2011, we entered into an agreement with Anadarko Petroleum Corporation (“Anadarko”) to transport excess gas production from the Spyglass Hill Unit through the EWM Pipeline, based on our expectation that third party gas volumes would increase in late 2012 or 2013.  However, Anadarko sold its interest in the Atlantic Rim in 2012, and the associated drilling plans changed.   Although the agreement remains in effect with the successor operator, Warren, it has only provided us with updates on its anticipated drilling plans through 2014.  Future development will be necessary for the production volumes from the Spyglass Hill Unit to reach a level that would necessitate use of our pipeline.

Spyglass Hill Unit

The Spyglass Hill Unit was established in 2011 and encompasses approximately 113,300 gross (9,900 net) acres in an area to the north, east and south of the Catalina Unit. Our working interest in the unit is approximately 8.9%. Although the former Sun Dog and Doty Mountain Units were dissolved upon establishment of the Spyglass Hill Unit, the existing PAs and our working interest therein remain intact. The Spyglass Hill Unit is operated by Warren.  

In the Sun Dog PA, we have ownership in a total of 10,851 gross (3,102 net) acres. As of December 31, 2013, our working interest was 28.59% in the 114 production wells within this PA. In the Doty Mountain PA, we have ownership in a total of 6,884 acres (1,840 net). Our working interest as of December 31, 2013 was 26.73% in the 60 production wells in this PA. The operator drilled and completed 27 additional wells in the third quarter of 2013.  As a result of the new wells, the PA will expand, and upon BLM approval our working interest will change to approximately 23% in the 87 wells.  During 2013, net production from the Spyglass Hill Unit totaled 1,948 MMcf, or an average daily net production of 5,337 Mcf per day, representing a decrease of 13% as compared to 2012. CBM wells can become saturated with water when they are not producing or properly maintained. We believe the production decrease is primarily due to delayed maintenance by the former operator.   Production from the new wells was not material in 2013 due to incomplete compression and gathering systems. We also have interest in 6,282 gross (757 net) acres in the Grace Point Unit. This unit consists of 26 production wells. For the year ended December 31, 2013, sales net to our interest from the Grace Point Unit were insignificant.

The federal exploratory agreement governing the Spyglass Hill Unit states that a minimum of 25 wells must be drilled by June of each year, or this unit will terminate. Warren drilled 27 wells during 2013, fulfilling the federal requirement for the current year.  We have been notified that Warren plans to drill 48 wells throughout the Spyglass Hill Unit in 2014, which will satisfy the minimum well requirement through June 2015.  If the Spyglass Hill Unit were to terminate due to insufficient drilling activity, any undeveloped acreage at the time of termination would be extended for two years and then expire, if still undeveloped.

The Pinedale Anticline in the Green River Basin of Wyoming

The Pinedale Anticline is in southwestern Wyoming, ten miles south of the town of Pinedale. QEP Resources, Inc. operates 2,400 acres covering three separate Mesa Units in which we hold a net acreage position of 124 acres. The Mesa Units on the Pinedale Anticline include approximately 218 non-operated wells that represented 20% of our total production for 2013. Our net production from the Mesa Units in 2013 was 1,801 MMcfe, or 4,934 Mcfe per day, net to our interest.

As of December 31, 2013, in the Mesa “A” PA, there were 45 producing wells, in which we hold a 0.3125% overriding royalty interest. We own approximately 600 gross (1.875 net) acres in the Mesa “A” PA.

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In the Mesa “B” PA, where we have an 8% average working interest in the shallow producing formations and a 12.5% average working interest in the deep producing formations, there were 139 producing wells that produced 1,552 MMcfe in 2013, net to our interest, a decrease of 13% as compared to 2012. We have 600 gross (64 net) acres in the shallower formations in the “B” PA, and 800 gross (100 net) acres in the deep producing formations. Eleven of the 139 wells came on-line for production during the first and second quarters 2013. We are also currently participating in the completion of one additional well, which is estimated to be completed during 2014. With the completion of this well, the unit will be fully drilled and we expect the operator to shift its efforts to drilling and development of Mesa “A” and once fully drilled, onto Mesa “C”.

In the Mesa “C” PA, where we have a working interest of 6.4%, 34 wells produced 268 MMcfe in 2013, net to our interest, a decrease of 13% as compared to 2012. We have 1,000 gross (65.27 net) acres in the Mesa “C” PA.

At year end, we had working interests or overriding royalty interests in a total of 4,840 acres in and around this developing natural gas field.

Exploration Opportunities

Niobrara Shale Formation

The Niobrara Shale formation (“Niobrara”) is an emerging oil play in the Rocky Mountain region of the United States. Niobrara is a thick and continuous Cretaceous source rock that ranges from 150 feet to 1,500 feet thick.  We completed a 9,400 foot test well located within our Atlantic Rim play in the first quarter of 2013.  This well targeted the deep gas zones of the Frontier and Dakota formations and in three benches of the Niobrara formation.  Our working interest in this well is 95% before payout. After payout, our working interest will decrease to 87%.

We brought the well on-line in the first quarter of 2013, and although the initial production results were encouraging, we have ultimately been unable to establish commercial oil production to date.  The well is currently producing natural gas from the Niobrara formation.  The Company filed an application with the Wyoming Oil and Gas Commission to comingle gas production from the Frontier, Dakota, and Niobrara formations produced from the well and are awaiting approval as of the date of this report.  Upon approval, we expect to begin producing gas from the Dakota and Frontier formations in the third quarter of 2014.  

Utilizing our reservoir analysis and production results to date, in the fourth quarter of 2013 we concluded that we did not expect to recover the full amount of the capitalized costs associated with this well.  Impairment expense related to this well totaled $4,812 for the year ended December 31, 2013.  We had previously recorded an impairment related to this well in the year ended December 31, 2012.  Total impairment recorded on the well to date is $9,242.  

We hold other acreage in Wyoming and western Nebraska that we believe to have Niobrara exposure.  The acreage consists of leases in the following areas as of December 31, 2013:

 

We are actively looking for partnership opportunities related to this acreage.  

Northeast Nevada

We have leased 22,493 gross (6087 net) acres, in the Huntington Valley in Elko and White Pine Counties, Nevada.  Recently, Noble Energy informed us that in 2014 it intends to form a federal exploratory unit in the area that would include a portion of our acreage.  The play has unconventional oil potential.  

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Main Fork Unit in Utah

The Main Fork Unit (formerly the Table Top Unit) is located on a structural dome in the southwest corner of the Green River Basin, in Summit County, Utah. This structural dome is overlaid by the Wyoming Overthrust Belt and the North Flank Thrust of the Uinta Mountains. In early 2007, drilling at the Table Top Unit #1 (“TTU #1”) well reached the originally planned depth of 15,760 feet. The drilling did not find reservoir rocks with sufficient permeability, and operations were suspended to assess alternative approaches to completing the project. In June 2009, the BLM approved a suspension of operations (“SOP”) and production for all leases within the Main Fork Unit. The SOP stops the expiration of lease terms and halts any lease rentals until an environmental impact study is completed, which is expected to take three or more years to complete. During the EIS, we are not prevented from exercising our approved rights to re-enter the TTU #1, or drill a new well at the TTU #3 site.  In 2009 we entered into an optional farm-out agreement with a third-party, however, we were notified in April 2013 that the third party would not exercise its farm-in right.  We are currently looking for a new partner on this project.  The BLM and State of Utah have conditionally approved us to temporarily abandon the well and have not required us to plug it at this time.  

Reserves

We engaged an independent petroleum engineering firm, Netherland, Sewell & Associates, Inc. (“NSAI”) to prepare our reserve estimates at December 31, 2013, 2012 and 2011. NSAI is a worldwide leader in petroleum property analysis for industry and financial organizations, and government agencies. NSAI was founded in 1961 and performs consulting petroleum engineering services under the Texas Board of Professional Engineers Registration No. F-2699. Within NSAI, the technical persons primarily responsible for preparing the estimates set forth in the NSAI reserves report included herein are David Miller and John Hattner. Mr. Miller has been practicing consulting petroleum engineering at NSAI since 1997. Mr. Miller is a Registered Professional Engineer in the State of Texas (License No. 96134) and has over 30 years of practical experience in petroleum engineering, with over 15 years of experience in the estimation and evaluation of reserves. Mr. Hattner has been practicing consulting petroleum geology at NSAI since 1991. Mr. Hattner is a Certified Petroleum Geologist and Geophysicist in the State of Texas (License No. 559) and has over 31 years of practical experience in petroleum geosciences, with over 20 years of experience in the estimation and evaluation of reserves. Mr. Miller and Mr. Hattner both 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; both are proficient in judiciously applying industry standard practices to engineering and geosciences evaluations as well as applying SEC and other industry reserves definitions and guidelines.

 

Our Vice President, Operations (“VP Operations”) is the technical person primarily responsible for overseeing the preparation of our proved reserves estimates by our independent petroleum engineers. Our VP Operations received a PhD in Petroleum Engineering from the Colorado School of Mines and is a licensed Professional Engineer with over 30 years of experience in petroleum engineering and oil and gas operations, including extensive experience in reservoir analysis.  To ensure accuracy and completeness of the data prior to submission to NSAI, the information we provide is reviewed by the VP Operations.  Our internal control process also includes a review of the assumptions used and a reconciliation of the year to year changes.

NSAI evaluated properties representing a minimum of 99% of our reserves, valued at the total estimated future net cash flows before income taxes, discounted at 10% (“PV-10”), for all periods presented below. In estimating the proved reserves and future revenue, NSAI used technical and economic data including, but not limited to, well logs, geologic maps, seismic data, well test data, production data, historical price and cost information, and property ownership interests. Senior members of our finance, engineering and geology teams review the final reserve report to verify the accuracy and completeness of all inputs into the report. NSAI’s report to management, which summarizes the scope of work performed and its conclusions, has been included in this report as Exhibit 99.1.

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All of our proved reserves, as shown in the table below, are located within the continental United States.

 

Reserve estimates are inherently imprecise and are subject to revisions based on production history, results of additional exploration and development, prices of oil and gas, and other factors. Accordingly, reserves estimates may vary from the quantities of oil and natural gas that are ultimately recovered. For more information regarding the inherent risks associated with estimating reserves, see Item 1A. “Risk Factors.”

 

Proved undeveloped reserves totaled 14.9 Bcfe and 5.7 Bcfe for the years ended December 31, 2013 and 2012, respectively.  During the year ended December 31, 2013, we had net positive revisions of approximately 10.8 Bcfe in proved undeveloped reserves primarily due to the increase in natural gas prices, which made development of these reserves, primarily located in the Mesa “C” PA, economic. During 2013, the Company invested approximately $1.2 million to convert 3.3 Bcfe proved undeveloped reserves into proved developed reserves.  The conversion of these undeveloped reserves into developed reserves was due to developmental drilling in the Mesa Units on the Pinedale Anticline.  We also had extensions and discoveries of 1.6 Bcfe primarily located in the Mesa “C” PA.  Due to continued drilling success in this area, additional wells planned by the operator are now expected to be drilled within the five years.  We do not have any material concentrations of reserves that have remained undeveloped for a period of five years or more.

The table below shows our reconciliation of our PV-10 to our standardized measure of discounted future net cash flows (the most directly comparable measure calculated and presented in accordance with GAAP). PV-10 is our estimate of the present value of future net revenues from estimated proved oil and natural gas reserves after deducting estimated production and ad valorem taxes, future capital costs and operating expenses, but before deducting any estimates of future income taxes. The estimated future net revenues are discounted at an annual rate of 10% to determine their present value. We believe PV-10 to be an important measure for evaluating the relative significance of our oil and natural gas properties and that the presentation of the non-GAAP financial measure of PV-10 provides useful information to investors because it is widely used by professional analysts and sophisticated investors in evaluating oil and gas companies. Because there are many unique factors that can impact an individual company when estimating the amount of future income taxes to be paid, we believe the use of a pre-tax measure is valuable for evaluating our company. We believe that most other companies in the oil and gas industry calculate PV-10 on the same basis. PV-10 should not be considered as an alternative to the standardized measure of discounted future net cash flows as computed under GAAP. Reference should also be made to the Supplemental Oil and Gas Information included in Item 15, Note 12 to the Notes to the Consolidated Financial Statements for additional information.

 

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Reserve estimates may vary from the quantities of oil and natural gas that are ultimately recovered. The PV-10 values shown in the aforementioned table are not intended to represent the current market value of the estimated proved oil and gas reserves owned by us. The PV-10 value above does not include the impact of our outstanding financial hedges. The 10% discount factor used to calculate present value, which is required by Financial Accounting Standards Board pronouncements (“FASB”), is not necessarily the most appropriate discount rate. The present value, no matter what discount rate is used, is materially affected by assumptions as to timing of future production, which may prove to be inaccurate.

Production

The following table sets forth oil and gas production by geographic area from our net interests in producing properties for the years ended December 31, 2013, 2012 and 2011.

 

Derivative Instruments

We have entered into various derivative instruments to mitigate the risk associated with downward fluctuations in the natural gas price and the resulting impact on cash flow, net income, and earnings per share. Historically these derivative instruments have consisted of forward contracts, costless collars and swaps. The duration and size of our various derivative instruments varies, and depends on our view of market conditions, available contract prices and our operating strategy. Under our current credit agreement, we can hedge up to 90% of the projected proved developed producing reserves for the next 12-month period, and up to 80% of the projected proved producing reserves for the ensuing 24-month period.

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Our outstanding derivative instruments as of December 31, 2013 are summarized below:

 

We have a $30 million fixed rate swap contract with a third party in place as a hedge against the floating interest rate on our credit facility. Under the hedge contract terms, we locked in the Eurodollar LIBOR portion of the interest calculation at approximately 1.050% for this tranche of our outstanding debt, which based on our current level of outstanding debt translates to an interest rate on this tranche of approximately 3.55%. The contract is effective through September 30, 2016.

See Item 15, Notes 1, 4 and 6 to the Notes to the Consolidated Financial Statements for discussion regarding the accounting treatment of our derivative contracts.

Productive Wells

The following table categorizes certain information concerning the productive wells in which we owned an interest as of December 31, 2013. For purposes of this table, wells producing both oil and gas are shown in both columns. Of the wells included in the table below, we are the operator of 91 producing wells in Wyoming and one in Oklahoma.

 

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Drilling Activity

We drilled or participated in the drilling of wells as set forth in the following table for the periods indicated. In certain wells in which we participate, we have an overriding royalty interest and no working interest.

 

Acreage

The following tables set forth the gross and net acres of developed and undeveloped oil and gas leases in which we had working interests and royalty interests as of December 31, 2013. Certain acreage is included in both tables as we hold both a working interest and a royalty interest. Undeveloped acreage includes leasehold interests that may have been classified as containing proved undeveloped reserves.

Acreage by Working Interest:

 

 

Acreage by Royalty Interest:

 

 

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Substantially all of the leases summarized in the preceding table will expire at the end of their respective primary terms unless the existing leases are renewed, production has been obtained from the acreage subject to the lease prior to that date, or a suspension of a lease is granted. The following table sets forth the gross and net acres subject to leases summarized in the preceding table that will expire during the years indicated:

 

 

The above acreage does not include acreage that is currently held by production.

Significant Developments since December 31, 2012

During 2013, the operator of the Spyglass Hill Unit drilled 27 new wells, which satisfied the annual minimum drilling requirement per the federal exploratory agreement governing the Spyglass Hill Unit.   By fulfilling the minimum drilling requirement, the undeveloped acreage within the Spyglass Hill Unit will continue to be held by production.  The operator has informed us that it intends to drill to meet the 2014 and 2015 requirements as well.  

Eleven wells were completed on the Pinedale Anticline with one additional well completion expected in 2014.  Pending the completion of the one well, Mesa “B” will be drilled out.  The operator intends to move on to Mesa “A”, in which we hold an overriding royalty interest of 0.3125%.

Marketing and Major Customers

The principal products produced by us are natural gas and crude oil. These products are marketed and sold primarily to purchasers that have access to nearby pipeline facilities. Typically, oil is sold at the wellhead at field-posted prices and natural gas is sold both (i) under contract at negotiated prices based upon factors normally considered in the industry (such as distance from well to pipeline, pressure, quality) and (ii) at spot prices. We currently have no long-term delivery contracts in place.

The marketing of most of our products is performed by a third-party marketing company, Summit Energy, LLC. During the years ended December 31, 2013, 2012 and 2011, we sold 91%, 93% and 76%, respectively, of our total oil and gas sales volumes to Summit Energy, LLC. No other companies purchased more than 10% of our oil and gas production. Although a substantial portion of our production is purchased by one customer, we do not believe the loss of this customer would likely have a material adverse effect on our business because there are other customers in the area that would be accessible to us.

Title to Properties

Substantially all of our working interests are held pursuant to leases from third parties. A title opinion is usually obtained prior to the commencement of drilling operations on properties. We have obtained title opinions or conducted a thorough title review on substantially all of our producing properties and believe that we have satisfactory title to such properties in accordance with standards generally accepted in the oil and gas industry. The majority of the value of our properties is subject to a mortgage under our credit facility, customary royalty interests, liens for current taxes, and other burdens that we believe do not materially interfere with the use of or affect the value of such properties. We also perform a title investigation before acquiring undeveloped leasehold interests.

Seasonality

Generally, but not always, the demand and price levels for natural gas increase during the colder winter months and warmer summer months but decrease during the spring and fall (“shoulder months”). Pipelines, utilities, local distribution companies and industrial users utilize natural gas storage facilities and purchase some of their anticipated winter and summer requirements during the shoulder months, which can lessen seasonal demand fluctuations. We have entered into various financial derivative instruments for a portion of our production, which reduces our overall exposure to seasonal demand and resulting commodity price fluctuations.

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Competition

The oil and gas industry is highly competitive and we compete with a substantial number of other companies that have greater financial and other resources than we do. We encounter significant competition particularly in acquiring desirable leasehold acreage for our drilling and development operations, locating and acquiring prospective oil and natural gas properties, obtaining experienced and qualified oil service providers, obtaining purchasers and transporters of the oil and natural gas we produce and hiring and retaining key employees and other personnel. There is also competition between oil and natural gas producers and other industries producing energy and fuel. Our competitive position also depends on our geological, geophysical and engineering expertise, and our financial resources. We believe that the location of our leasehold acreage, our exploration, drilling and production expertise and the experience and knowledge of our management and industry partners generally enables us to compete effectively in our current operating areas.

Government Regulations

Exploration for, and production and marketing of, crude oil and natural gas are extensively regulated at the federal, state and local levels. Matters subject to regulation include the issuance of drilling permits, allowable rates of production, the methods used to drill and case wells, reports concerning operations (including hydraulic fracture stimulation reports), the spacing of wells, the unitization of properties, taxation issues and environmental protection (including long-term changes in weather patterns). These regulations are under constant review and may be amended or changed from time-to-time in response to economic or political conditions. Pipelines are also subject to the jurisdiction of various federal, state and local agencies. Our ability to economically produce and sell crude oil and natural gas is affected by a number of legal and regulatory factors, including federal, state and local laws and regulations in the US and laws and regulations of foreign nations. Many of these governmental bodies have issued rules and regulations that are often difficult and costly to comply with, and that carry substantial penalties for failure to comply. These laws, regulations and orders may restrict the rate of crude oil and natural gas production below the rate that would otherwise exist in the absence of such laws, regulations and orders. The regulatory burden on the crude oil and natural gas industry increases our costs of doing business and consequently affects our profitability. See Item 1A. Risk Factors – We are subject to various governmental regulations and environmental risks that may cause us to incur substantial costs.

Examples of US federal agencies with regulatory authority over our exploration for, and production and sale of, crude oil and natural gas include:

Most of the states within which we operate have separate agencies with authority to regulate related operational and environmental matters. Some of the counties and municipalities within which we operate have adopted regulations or ordinances that impose additional restrictions on our oil and gas exploration, development and production.

We participate in a substantial percentage of our wells on a non-operated basis, and accordingly may be limited in our ability to control some risks associated with these natural gas and oil operations. We believe that operations where we own interests, whether operated or not, comply in all material respects with the applicable laws and regulations and that the existence and enforcement of these laws and regulations have no more restrictive an effect on our operations than on other similar companies in our industry.

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Environmental Laws and Regulations

Our operations are subject to numerous federal, state and local laws and regulations governing the siting of operations, the release of materials into the environment or otherwise relating to environmental protection. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentration of various substances that can be released into the environment in connection with drilling and production activities, limit or prohibit drilling activities on specified lands within wilderness, wetlands and other protected areas, require remedial measures to mitigate pollution from former operations, such as pit closure and plugging abandoned wells, and impose substantial liabilities for pollution resulting from production and drilling operations. To the extent laws are enacted or other governmental action is taken that restricts drilling or imposes more stringent and costly waste handling, disposal and cleanup requirements, our business and prospects could be adversely affected.

The National Environmental Policy Act (“NEPA”) requires a thorough review of the environmental impacts of “major federal actions” and a determination of whether proposed actions on federal land would result in “significant impact”. For oil and gas operations on federal lands or requiring federal permits, NEPA review can increase the time for obtaining approval and impose additional regulatory burdens on the natural gas and oil industry, thereby increasing our costs of doing business and our profitability. The Federal Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, also known as the “Superfund” law, imposes liability, without regard to fault, on certain classes of persons with respect to the release of a “hazardous substance” into the environment. The Resource Conservation and Recovery Act imposes regulations on the management, handling, storage, transportation and disposal of solid and hazardous wastes, and may also impose cleanup liability on certain classes of persons regulated under that federal statute. Our operations may also be subject to the Clean Air Act, the Clean Water Act, the Endangered Species Act, the National Historic Preservation Act and a variety of other federal, state and local review, mitigation, permitting, reporting, and registration requirements relating to protection of the environment. We believe that we, as operators, and the outside operators with which we do business are in substantial compliance with current applicable federal, state and local environmental laws and regulations and that continued compliance with existing requirements will not have a material adverse effect on us. Nevertheless, changes in environmental laws have the potential to adversely affect operations.

It is customary in our industry to recover natural gas and oil from formations through the use of hydraulic fracturing. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into rock formations to stimulate natural gas production. These formations are generally geologically separated and isolated from fresh ground water supplies by protective rock layers. We find that the use of hydraulic fracturing is necessary to produce commercial quantities of natural gas and oil from many reservoirs, including the CBM wells in the Atlantic Rim. Currently, regulation of hydraulic fracturing is primarily conducted at the state level through permitting and other compliance requirements. Concern around the exploration and development of shale gas using hydraulic fracturing has continued to grow, which may give rise to additional regulation in this area. If passed into law, such efforts could have an adverse effect on our operations.

We have made and will continue to make expenditures in our efforts to comply with environmental requirements. We do not believe that we have, to date, expended material amounts in connection with such activities or that compliance with such requirements will have a material adverse effect on our capital expenditures, earnings or competitive position. Although such requirements do have a substantial impact on the crude oil and natural gas industry, we do not believe that they affect us to any greater or lesser extent than other companies in the industry.

Employees and Office Space

As of December 31, 2013, we had 22 employees. None of our employees is subject to a collective bargaining agreement.  We lease 7,470 square feet of office space in Denver, Colorado, for our principal executive offices. We also own 6,765 square feet of office space in Casper, Wyoming.

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Available Information

Our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, and amendments to reports filed or furnished pursuant to Sections 13(a) and 15(d) of the Securities Exchange Act of 1934, as amended, are available on our website at http://www.dble.com/, as soon as reasonably practicable after we electronically file such reports with, or furnish those reports to the SEC.  Our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q and amendments to reports are available free of charge by writing to:

Double Eagle Petroleum Co.

c/o John Campbell, Investor Relations

1675 Broadway, Suite 2200

Denver, CO 80202

We maintain a code of ethics applicable to our Board of Directors, principal executive officer, and principal financial officer, as well as all of our other employees. A copy of our Code of Business Conduct and Ethics and our Whistleblower Procedures may be found on our website at http://www.dble.com/, under the Corporate Governance section. These documents are also available in print to any stockholder who requests them. Requests for these documents may be submitted to the above address.

Information on our website is not incorporated by reference into this Form 10-K/A and should not be considered a part of this document.

Glossary

The terms defined in this section are used throughout this Annual Report on Form 10-K/A.

2-D seismic. The standard acquisition technique used to image geologic formations over a broad area. Data is collected by a single line of energy sources which reflect seismic waves to a single line of geophones. 2-D seismic data produces an image of a single vertical plane of sub-surface data.

3-D seismic. A three dimensional seismic survey employing three-component geophones. These multi-component geophones record three orthogonal components of ground motion and provide information about shear waves that are unobtainable by conventional 2-D seismic surveys.

Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil or other liquid hydrocarbons.

Bcf. Billion cubic feet, used in reference to natural gas.

Bcfe. Billion cubic feet of gas equivalent. Gas equivalents are determined using the ratio of six Mcf of gas (including gas liquids) to one Bbl of oil.

Btu. A British Thermal Unit is the amount of heat required to raise the temperature of a one-pound mass of water by one degree Fahrenheit.

Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive in an attempt to recover proved undeveloped reserves.

Dry hole. A well found to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.

Estimated net proved reserves. The estimated quantities of oil, gas and gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.

Exploratory well. A well drilled to find and produce oil or gas in an unproved area, to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir or to extend a known reservoir beyond its productive horizon.

Economically producible. A resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation.

Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature or stratigraphic condition.

Gross acre. An acre in which a working interest is owned.

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Gross well. A well in which a working interest is owned.

Hydraulic fracturing. The injection of water, sand and additives under pressure, usually down casing that is cemented in the wellbore, into prospective rock formations at depth to stimulate natural gas and oil production.

MBbl. One thousand barrels of oil or other liquid hydrocarbons.

Mcf. One thousand cubic feet.

Mcfe. One thousand cubic feet of gas equivalent. Gas equivalents are determined using the ratio of six Mcf of gas (including gas liquids) to one Bbl of oil.

MMcf. One million cubic feet.

MMcfe. One million cubic feet of gas equivalent. Gas equivalents are determined using the ratio of six Mcf of gas (including gas liquids) to one Bbl of oil.

MMBtu. One million British Thermal Units.

Net acres or net wells. The sum of our fractional working interests owned in gross acres or gross wells.

Participating area or PA. A spacing unit established for producing well within a federal exploratory unit approved by the BLM. All interest owners in the PA share in all well(s) production on a proportional basis to their interest in the PA. As more wells are drilled adjacent to the PA, the PA is enlarged or revised. At each revision, all interest owner’s participation is recalculated.

Permeability. The ability, or measurement of a rock’s ability, to transmit fluids. Formations that transmit fluids readily, such as sandstones, are described as permeable and tend to have many large, well-connected pores. Impermeable formations, such as shales and siltstones, tend to be finer grained or of a mixed grain size, with smaller, fewer, or less interconnected pores.

Productive well. A well that is producing oil or gas or that is capable of production.

Proved developed reserves. Proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

Proved reserves. The quantities of oil, natural gas and natural gas liquids, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs under existing economic conditions and operating conditions.

Proved undeveloped reserves. Proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

PV-10 value. The present value of estimated future gross revenue to be generated from the production of estimated net proved reserves, net of estimated production and future development costs, using prices and costs in effect as of the date indicated (unless such prices or costs are subject to change pursuant to contractual provisions), without giving effect to non-property related expenses such as general and administrative expenses, debt service and future income tax expenses or to depreciation, depletion and amortization, discounted using an annual discount rate of 10 percent. While this measure does not include the effect of income taxes as it would in the use of the standardized measure calculation, it does provide an indicative representation of the relative value of the company on a comparative basis to other companies and from period to period.

Royalty. The share paid to the owner of mineral rights expressed as a percentage of gross income from oil and gas produced and sold unencumbered by expenses relating to the drilling, completing and operating of the affected well.

Royalty interest. An interest in an oil and gas property entitling the owner to shares of oil and gas production free of costs of exploration, development and production.

Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas, regardless of whether such acreage contains estimated net proved reserves.

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Unitization. A type of sharing arrangement by which owners of operating and non-operating working interests pool their property interests in a producing area to form a single operating unit. The share that each interest owner receives is based upon the respective acreage contributed by each owner in the participating area.

Working interest. The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and to share in the production. Working interest owners also share a proportionate share of the costs of exploration, development, and production costs.

 

ITEM 1A. RISK FACTORS

Investing in our securities involves risk. In evaluating us, careful consideration should be given to the following risk factors, in addition to the other information included or incorporated by reference in this Form 10-K/A. Each of these risk factors, as well as other risks described elsewhere in this Form 10-K/A, could materially adversely affect our business, operating results or financial condition, as well as adversely affect the value of an investment in our common or preferred stock. See “Cautionary Note about Forward-Looking Statements” for additional risks and information regarding forward-looking statements.

Risks Related to the Oil and Natural Gas Industry and Our Business

We cannot control the future price of natural gas and sustained low prices could hurt our profitability, financial condition or ability to grow or could impair our ability to satisfy fixed payment obligations on our indebtedness.

Natural gas comprised approximately 98% of our total production for the year ended December 31, 2013 and represented 97% of our reserves as of December 31, 2013. Our revenues, profitability, liquidity, future rate of growth and the carrying value of our properties depend heavily on prevailing prices for natural gas. Historically, natural gas prices have been highly volatile, particularly in the Rocky Mountain region of the United States, and in the past several years have been depressed by excess total domestic natural gas supplies. Prices have also been affected by actions of federal, state and local governments and agencies, foreign governments, national and international economic and political conditions, levels of consumer demand, weather conditions, domestic and foreign supply of oil and natural gas, proximity and capacity of gas pipelines and other transportation facilities, and the price and availability of alternative fuels. In addition, sales of natural gas are seasonal in nature, leading to substantial differences in cash flow at various times throughout the year. These external factors and the volatile nature of the energy markets make it difficult to estimate future prices of natural gas. Any substantial or extended decline in the price of natural gas would have a material adverse effect on our financial condition and results of operations, including reduced cash flow and borrowing capacity and lower reserves. Price volatility also makes it difficult to budget for and project the return on potential acquisitions and development and exploration projects, and sustained lower gas prices may cause us or the operators of properties in which we have ownership interests to curtail some projects and drilling activity.  Because we are significantly leveraged, a substantial decrease in our revenue as a result of lower commodity prices could impair our ability to satisfy payment obligations on our indebtedness or pay our preferred stock dividends, and our funds available for operations and future business opportunities will be reduced by that portion of our cash flow required to make such payments.

We do not control all of our operations and development projects.

Certain of our business activities are conducted through operating agreements under which we own partial interests in oil and natural gas wells. If we do not operate wells in which we own an interest, we do not have control over normal operating procedures, expenditures or future development of underlying properties. The failure of an operator of our wells to adequately perform operations, or an operator’s breach of the applicable agreements, could reduce our production and revenues. The success and timing of drilling and development activities on properties operated by others therefore depends upon a number of factors outside of our control, including the operator’s:

Since we do not have a majority ownership interest in most of the wells that we do not operate, we may not be in a position to remove the operator in the event of poor performance.

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The federal exploratory agreement governing the Spyglass Hill Unit states that a minimum of 25 wells must be drilled by June of each year, or the unit will be terminated. The undeveloped acreage that falls within the boundaries of the Spyglass Hill Unit is currently held by production and is not subject to expiration, as Warren met the minimum drilling requirement for 2013. However, if the Spyglass Hill Unit terminates, any undeveloped acreage at that time would be extended for two years and if it remains undeveloped (at the end of such two year period), the existing leases in the unit will expire. We would lose our opportunity to drill and produce new wells on any expired leases. Warren has informed us that it plans to drill 48 wells in 2014, which will satisfy the drilling requirement through 2015.  The unit operating agreement governing the Spyglass Hill Unit requires well drilling proposals to be approved by a majority of the working interest owners. Warren owns a majority interest in the field, and therefore drilling is ultimately at its discretion.

The exploration, development and operation of oil and gas properties involve substantial risks that may result in a total loss of investment.

Exploring for and, to a lesser extent, developing and operating oil and gas properties involve a high degree of business and financial risk, and thus a substantial risk of loss of investment. We may drill wells that are unproductive or, although productive, do not produce oil and/or natural gas in sufficient quantities to cover the drilling, operating and other costs. Acquisition and completion decisions generally are based on subjective judgments and assumptions that are speculative. We cannot predict with certainty the production potential of a particular property or well. Furthermore, a successful completion of a well does not ensure a profitable return on the investment. There are a variety of geological, operational, and market-related factors that may substantially delay or prevent completion of any well or otherwise prevent a property or well from being profitable. These include:

We recorded impairment charges totaling $4,812 and $4,430 for the years ended December 31, 2013 and 2012, respectively, related to our Atlantic Rim Niobrara exploration well, which was completed in the first quarter of 2013.  We have been unable to establish commercial oil production from this well.  The well is currently producing a small amount of natural gas from the Niobrara formation, and we expect to begin producing gas from the Dakota and Frontier formation in the third quarter of 2014.  However, the expected future net cash from the natural gas was insufficient to recover the full drilling and completion costs of the Atlantic Rim Niobrara exploration well.  

Indebtedness may limit our liquidity and financial flexibility.

As of December 31, 2013, we had $47,450 drawn under our bank credit facility and we had 1,610,000 shares of our Series A Preferred Stock outstanding, (redeemable at our option), which require payment of cumulative cash dividends at a rate of 9.25% per year.

Our indebtedness affects our operations in several ways, including;

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We may incur additional debt in order to fund our exploration, development and acquisition activities. A higher level of indebtedness increases the risk that our liquidity may become impaired and we may default on our debt obligations. Our ability to meet our debt obligations and reduce our level of indebtedness depends on future performance. General economic conditions, natural gas and oil prices and financial, business and other factors will affect our operations and our future performance. Many of these factors are beyond our control. We may not be able to generate sufficient cash flow to pay the interest on our debt, and future working capital, borrowings and equity financing may not be available to pay or refinance such debt.

Our operations require substantial capital and we may be unable to fund our planned capital expenditures.

The oil and gas industry is capital intensive. We spend and will continue to spend a substantial amount of capital for the acquisition, exploration, exploitation, development and production of natural gas and oil reserves. We have historically addressed our short and long-term liquidity needs through the use of cash flow provided by operating activities, borrowing under bank credit facilities, and the issuance of equity. Without adequate capital we may not be able to successfully execute our operating strategy. The availability of these sources of capital will depend upon a number of factors, some of which are beyond our control. These factors include:

If low natural gas prices, lack of adequate gathering or transportation facilities, operating difficulties or other factors, many of which are beyond our control, cause our revenues and cash flows from operating activities to decrease, we may be limited in our ability to obtain the capital necessary to complete our capital expenditures program.

We may be unable to develop our existing acreage due to the environmental and political pressures around natural resource development.

Our anticipated growth and planned expenditures are based upon the assumption that existing leases and regulations will remain intact and allow for the future development of carbon-based fuels. However, the United States federal government has not adopted a clear energy policy, and policy decisions continue to be complicated by the political situation in Washington D.C. Our ability to develop known and unknown reserves in areas in which we have reserves or leases may be limited, thereby limiting our ability to grow and generate cash flows from operations.

The largest portion of our anticipated growth and planned capital expenditures is expected to be from properties located in the Atlantic Rim that are covered by the Atlantic Rim Environmental Impact Study (“EIS”). In May 2007, the final Record of Decision for the Atlantic Rim EIS was issued, which allowed us and other operators in the area to pursue additional coalbed methane drilling. Three separate coalitions of conservation groups appealed the approval of the EIS to the Bureau of Land Management (“BLM”). All of the appeals were subsequently dismissed. Although the appeals were dismissed, the BLM does allow public comment during the permitting process. In October 2012, the National Wildlife Federation and Wyoming Wildlife Federation filed an appeal with the Interior Board of Land Appeals (“IBLA”) regarding the Finding of No Significant Impact (“FONSI”) and Decision Record for the development plan and certain drilling permits that have been issued in an undeveloped area of the Catalina Unit. The BLM issues a FONSI upon completion of an environmental impact assessment related to permit applications. The appeal asserts that BLM did not consider new environmental information when issuing the FONSI. The IBLA concluded that the environmental groups have sufficient support to pursue their claim in the federal court system. At this time the outcome of this appeal and its impact on future permits in the Atlantic Rim is uncertain. Appeals and pressure from conservation and environmental groups could ultimately delay or prevent drilling in this area.

Our operations are subject to governmental risks that may impact our operations.

Our operations have been, and at times in the future may be, affected by political developments and are subject to complex federal, state, local and other laws and regulations such as those related to:

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In order to conduct our operations in compliance with these laws and regulations, we must obtain and maintain numerous permits, approvals and certificates from various federal, state and local governmental authorities. We may incur substantial costs in order to maintain compliance with these existing laws and regulations. Failure to comply with these laws and regulations also may result in the suspension or termination of our operations and/or subject us to administrative, civil and criminal penalties. In addition, our costs of compliance may increase if existing laws or regulations, including environmental and tax laws, and regulations are revised or reinterpreted, or if new laws or regulations become applicable to our operations. For example, currently proposed federal legislation and regulation, that, if adopted, could adversely affect our business, financial condition and results of operations, include legislation and regulation related to hydraulic fracturing, derivatives, and environmental regulations, which are each discussed below.

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We may be unable to find additional reserves, which would adversely impact our ability to sustain production levels.

Our future operations depend on whether we find, develop or acquire additional reserves that are economically recoverable. Our properties produce oil and gas at a declining rate. Unless we acquire properties containing proved reserves or conduct successful exploration and development activities, or both, our proved reserves, production and revenues will decline over time. There are no assurances that we will be able to find, develop or acquire additional reserves to replace our current and future production at acceptable costs, or at all.

We may incur more taxes and certain of our projects may become uneconomic if certain federal income tax deductions currently available with respect to oil and natural gas exploration and development are eliminated as a result of future legislation.

The current administration has proposed eliminating certain key U.S. federal income tax deductions and credits currently available to natural gas and oil exploration and production companies. These changes include, but are not limited to:

It is unclear whether any of the foregoing changes will be enacted or how soon any such changes could become effective. Any such changes could negatively impact our financial condition and results of operations by increasing the costs we incur, which in turn could make it uneconomic to drill some prospects if commodity prices are not sufficiently high, resulting in lower revenues and decreases in production and reserves.

The shortage or high cost of equipment, personnel and other oil field services could adversely affect our ability to execute our exploration and development plans on a timely basis and within our budget.

Our industry is cyclical and, from time to time, there is a shortage of equipment, qualified personnel, and oil field services. Regardless of the economic conditions, competition for experienced technical and other professional personnel remains strong. If we cannot retain our current personnel or attract additional experienced personnel, our ability to compete could be adversely affected.

Also, as part of our business strategy, we rely on oil field service groups for a number of services, including drilling, cementing and hydraulic fracturing. Due to the increasing activity and attractiveness of the shale opportunities across the United States, there is increased competition for qualified and experienced crews in the Rocky Mountain region.

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Natural gas and oil drilling and production operations can be hazardous and expose us to liabilities.

The exploration, development and operation of oil and gas properties involves a variety of operating risks, including the risk of fire, explosions, blowouts, hole collapse, pipe failure, abnormally pressured formations, natural disasters, vandalism, and environmental hazards, including gas and oil leaks, pipeline ruptures or discharges of toxic gases. These industry-related operating risks can result in injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigation and penalties, and suspension of operations which could result in substantial losses.

We maintain insurance against some, but not all, of the risks described above. Such insurance may not be adequate to cover losses or liabilities. Also, we cannot predict the continued availability of insurance at premium levels that justify its purchase. The occurrence of a significant event that is not fully insured or indemnified against could materially and adversely affect our financial condition and operations.

Hydraulic fracturing may exposes us to operational and financial risks.

It is customary in our industry to recover natural gas and oil from formations through the use of hydraulic fracturing. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into rock formations to stimulate natural gas and oil production.  This process creates fractures in the rock formation within the reservoir which enables natural gas and oil to migrate to the wellbore. We find the use of this technique necessary to produce commercial quantities of natural gas and oil from many reservoirs, including the CBM wells in the Atlantic Rim.  

Our hydraulic fracturing operations subject us to operational and financial risks inherent in the drilling and production of oil and natural gas, including relating to underground migration or surface spillage due to uncontrollable flows of oil, natural gas, formation water or well fluids, as well as any related surface or ground water contamination, including from petroleum constituents or hydraulic fracturing chemical additives. Ineffective containment of surface spillage and surface or ground water contamination resulting from our hydraulic fracturing operations, including from petroleum constituents or hydraulic fracturing chemical additives, could result in environmental pollution, remediation expenses and third party claims alleging damages, which could adversely affect our financial condition and results of operations.

We may be unable to find reliable and economic markets for our gas production.

All of our current natural gas production is produced in the Rocky Mountain region, and there is a limited amount of transportation volume availability for all of the area producers. Although there are numerous transportation pipeline projects, we cannot predict whether these new pipelines will add enough capacity in the future. We have contracts with marketing companies that provide for the availability of transportation for our natural gas, but interruption of any transportation line out of the Rocky Mountains could have a material impact on our financial condition.

In addition, the transportation providers have gas quality requirements, including Btu content, and carbon dioxide content. The gas we produce in the Catalina Unit is transported on the Southern Star Transportation line, which has various gas quality requirements, including that gas must have carbon dioxide content below 1%. We are currently in compliance with this requirement; however, in certain prior years our carbon dioxide exceeded this limit. If this recurs, and we are unable to obtain a waiver we may incur additional costs to process this gas, or we may experience a production interruption at certain wells, which could have a material adverse impact on our cash flow and results of operations.

Acquisitions are a part of our growth strategy, and we may not be able to identify, execute, or integrate acquisitions successfully.

There is strong competition for acquisition opportunities in our industry, and this can be particularly challenging for a company of our size and capital structure. Our ability to identify and complete acquisitions is dependent upon, among other things, our ability to obtain debt and equity financing and, in some cases, regulatory approvals. Our ability to pursue our acquisition strategy may be hindered if we are not able to obtain financing or regulatory approvals on economically attractive terms, or at all. Additionally, competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions.

We could be subject to significant liabilities related to acquisitions. The successful acquisition of producing and non-producing properties requires an assessment of a number of factors, many of which are beyond our control. These factors include recoverable reserves, future oil and gas prices, operating costs and potential environmental and other liabilities, title issues and other factors. It generally is not feasible to review in detail every individual property included in an acquisition. Ordinarily, a review is focused on higher valued properties. Further, even a detailed review of all properties and records may not reveal existing or potential problems, nor will it permit us to become sufficiently familiar with the properties to assess fully their deficiencies and capabilities. We do not always inspect every well we acquire, and environmental problems, such as groundwater contamination, are not necessarily observable even when an inspection is performed. We cannot assure you that we will realize the expected benefits or synergies of a transaction.

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Acquisitions also often pose integration risks and difficulties. In connection with future acquisitions, the process of integrating acquired operations into our existing operations may result in unforeseen operating difficulties and may require significant management attention and financial resources that would otherwise be available for the ongoing development or expansion of existing operations. Acquisitions could result in us incurring additional debt, contingent liabilities and expenses, all of which could have a material adverse effect on our financial condition and operating results.

Competition in the oil and natural gas industry is intense, and many of our competitors have greater financial and other resources than we do.

We operate in the highly competitive areas of oil and natural gas exploration, development and production. We face intense competition from both major integrated energy companies and other independent oil and natural gas companies, many of which have resources substantially greater than ours. We compete in each of the following areas:

Our competitors may be able to pay more for development prospects, productive oil and natural gas properties, or other companies and businesses, and may be able to define, evaluate, bid for and purchase a greater number of properties, prospects and companies than our financial or human resources permit. There is also growing pressure for companies to balance their oil to natural gas reserve ratios, primarily due to the decline in natural gas prices. This may further increase competition, particularly in the emerging shale plays. Our ability to develop and exploit our oil and natural gas properties and to acquire additional properties or companies in the future will depend upon our ability to successfully conduct operations, evaluate and select suitable properties and consummate transactions in this highly competitive environment.

Substantially all of our producing properties are located in the Rocky Mountains, making us vulnerable to risks associated with operating in one major geographic area.

Our operations have been focused on the Rocky Mountain region, which means our current producing properties and new drilling opportunities are geographically concentrated in that area. Because our operations are not as diversified geographically as many of our competitors, the success of our operations and our profitability may be disproportionately exposed to the effect of any regional events, including fluctuations in prices of natural gas and oil produced from the wells in the region, natural disasters, restrictive governmental regulations, transportation capacity constraints, weather, curtailment of production or interruption of transportation, and any resulting delays or interruptions of production from existing or planned new wells.

Our reserves and future net revenues may differ significantly from our estimates.

This report contains estimates of our proved oil and natural gas reserves and estimated future net revenues from proved reserves. The estimates of reserves and future net revenues are not exact and are based on many variable and uncertain factors, including assumptions required by the SEC related to oil and gas prices, operating expenses, capital expenditures, taxes, drilling plans and availability of funds. The process of estimating oil and natural gas reserves requires significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir. Therefore, these estimates are inherently imprecise.

Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves will vary from those estimated. Any significant variance could materially affect the estimated quantities and the value of our reserves. Our properties may also be susceptible to hydrocarbon drainage from production by other operators on adjacent properties. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and natural gas prices and other factors, many of which are beyond our control.

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The present value, discounted at 10%, of the pre-tax future net cash flows attributable to our net proved reserves included in this report should not be considered as the market value of our oil and gas reserves. In accordance with SEC requirements, we base the present value, discounted at 10%, of the pre-tax future net cash flows attributable to our net proved reserves on the average oil and natural gas prices during the 12-month period before the ending date of the period covered by this report determined as an unweighted, arithmetic average of the first-day-of- the-month price for each month within such period, adjusted for quality and transportation. The assumed costs to produce the reserves remain constant at the costs prevailing on the date of the estimate. Actual future prices and costs may be materially higher or lower than those used in the present value calculation. In addition, the 10% discount factor, which the SEC requires us to use in calculating our discounted future net revenues for reporting purposes, may not be the most appropriate discount factor based on our cost of capital from time to time and the risks associated with our business.

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

Oil and natural gas operations in the Rocky Mountains are adversely affected by seasonal weather conditions and lease stipulations designed to protect various wildlife. In certain areas on federal lands, drilling and other oil and natural gas activities can only be conducted during limited times of the year. This limits our ability to operate in those areas and can intensify competition during those times for drilling rigs, oil field equipment, services, supplies and qualified personnel, which may lead to periodic shortages. These constraints and the resulting shortages or high costs could delay our operations and materially increase our operating and capital costs.

Our hedging activities could result in financial losses or could reduce our income.

To achieve a more predictable cash flow and to reduce our exposure to adverse fluctuations in the prices of commodities, we currently, and will likely in the future, enter into hedging arrangements for a portion of our production revenues.  While the use of hedging arrangements limits the downside risk of adverse price movements, it also may limit future benefits from favorable price movements and expose us to the risk of financial loss in certain circumstances, including when there is a widening of the expected  price differential between the delivery point of our production and the delivery points assumed in our hedge transactions, or the counterparty to the hedging contract defaults on its contractual obligations.

A default by any of our counterparties, which are generally financial institutions or major energy companies, could have an adverse impact on our ability to fund our planned activities or could result in a larger percentage of our production being subject to commodity price changes. In our hedging arrangements, we use master agreements that allow us, in the event of default, to elect early termination of all contracts with the defaulting counterparty. If we choose to elect early termination, all asset and liability positions with the defaulting counterparty would be “net settled” at the time of election. “Net settlement” refers to a process by which all transactions between counterparties are resolved into a single amount owed by one party to the other.

We are exposed to counterparty credit risk as a result of our receivables.

We are exposed to risk of financial loss from trade, joint interest billing hedging activity and other receivables. In 2013, we sold approximately 91% of our natural gas volumes and crude oil to one counterparty, which may impact our overall credit risk. We monitor the creditworthiness of our counterparties on an ongoing basis. However, disruptions in the financial markets could lead to sudden changes in a counterparty’s liquidity, and it may be unable to satisfy its obligations to us. We are unable to predict sudden changes in financial market conditions or a counterparty’s creditworthiness or ability to perform. Even if we do accurately predict sudden changes, our ability to negate the risk may be limited depending upon market conditions.

Risks Related to Our Securities

The trading volatility and price of our common stock may be affected by many factors.

In addition to our operating results and business prospects, many other factors affect the volatility and price of our common stock. The most important of these, some of which are outside our control, are the following:

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Failure of our common stock to trade at reasonable prices and volumes may limit our ability to fund future potential capital needs through issuances or sales of our stock.

Provisions in our corporate documents and Maryland law could delay or prevent a change of control of Double Eagle, even if that change would be beneficial to our stockholders.

Our amended articles of incorporation and Second Amended and Restated by-laws contain provisions that may make a change of control of Double Eagle difficult, even if it may be beneficial to our stockholders, including the authorization given to our Board of Directors to issue and set the terms of preferred stock and limitations on stockholder’s ability to fill Board of Directors vacancies, remove directors, or vote by written consent.

In addition, as a Maryland corporation, we are subject to the provisions of the Maryland General Corporation Law. Maryland law imposes restrictions on some business combinations and requires compliance with statutory procedures before some mergers and acquisitions can occur. These provisions of Maryland law may have the effect of discouraging offers to acquire us even if the acquisition would be advantageous to our stockholders. The Company believes these provisions would not apply to mergers and acquisitions that are approved by the Board of Directors and stockholders.

 

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

 

ITEM 3. LEGAL PROCEEDINGS

From time to time, we are involved in various legal proceedings. These proceedings are subject to the uncertainties inherent in any litigation. We are defending ourselves vigorously in all such matters, and while the ultimate outcome and impact of any proceeding cannot be predicted with certainty, our management believes that the resolution of any proceeding will not have a material adverse effect on our financial condition or results of operations.

 

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

 

PART II

 

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

Common Stock

Market Information. Our common stock is currently traded on the NASDAQ Global Select Market under the symbol “DBLE”. The range of high and low sales prices for our common stock for each quarterly period from January 1, 2012 through December 31, 2013 as reported by the NASDAQ Stock Market, is set forth below:

 

On March 3, 2014, the closing sales price for the common stock as reported by the NASDAQ Global Select Market was $2.18 per share.

Holders. On March 3, 2014, the number of holders of record of our common stock was 847.

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Dividends. We have not paid or declared any cash dividends on our common stock in the past and do not intend to pay or declare any cash dividends in the foreseeable future. We currently intend to retain future earnings for the future operation and development of our business including exploration, development and acquisition activities. Any future dividends would be subordinate to the full cumulative dividends on all shares of our Series A Preferred Stock. Any future dividends would be issued at the sole discretion of our Board of Directors.  

Our credit facility limits the aggregate value of dividends to common shareholders in any fiscal year to no more than 40% of consolidated net income, provided that we are not in default on our credit facility.

Unregistered Sales of Securities.

There were no sales of unregistered equity securities during the year ended December 31, 2013.

Issuer Purchases of Equity Securities.

The table below summarizes repurchases of our common stock in the fourth quarter of 2013:

 

 

 

 

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ITEM 6. SELECTED FINANCIAL DATA

The following selected financial information should be read in conjunction with our consolidated financial statements and the accompanying notes.

 

 

 

 

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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

(In this Item 7, amounts in thousands of dollars, except share, per share data, and amounts per unit of production)

The following discussion and analysis should be read in conjunction with the “Selected Financial Data” and the accompanying consolidated financial statements and related notes included elsewhere in this Annual Report on Form 10-K. The following discussion contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. Forward-looking statements are not guarantees of future performance, and our actual results may differ materially from the results expressed  or implied in the forward-looking statements. Factors that might cause such differences include, but are not limited to, those discussed in the subsection entitled “Risk Factors” above, which are incorporated herein by reference. We assume no obligation to revise or update any forward-looking statements for any reason, except as required by law. See also “Cautionary Information About Forward-Looking Statements”.

BUSINESS OVERVIEW

We are an independent energy company engaged in the exploration, development, production and sale of natural gas and crude oil, primarily in Rocky Mountain basins of the western United States. Our core properties are located in southwestern Wyoming. Our current production primarily consists of natural gas from two core properties located in southwestern Wyoming. We have coalbed methane (“CBM”) reserves and production in the Atlantic Rim Area of the eastern Washakie Basin, and tight gas reserves and production on the Pinedale Anticline in the Green River Basin of Wyoming. Substantially all of our revenues are generated through the sale of natural gas and oil production at market prices and the settlement of commodity hedges.  We also hold acreage with exploration potential in the Greater Green River Basin of Wyoming and the Huntington Basin of Nevada.  Approximately 98% of our 2013 production volume was natural gas.

Our objective is to increase long-term shareholder value by profitably growing our reserves, production, revenues, and cash flow. To meet this objective, we primarily focus on: (i) selectively pursuing acquisitions or mergers; (ii) investing in and enhancing  our existing production wells and field facilities on operated and non-operated properties in the Atlantic Rim; (iii) continuing  participation in the development of tight sands gas wells at the Mesa Units on the Pinedale Anticline; and (iv) pursuing high quality exploration and strategic development projects with potential for providing long-term drilling inventories that generate high returns.

As of December 31, 2013, we had estimated proved reserves of 72.8 Bcf of natural gas and 314 MBbl of oil, or a total of 74.7 Bcfe. Of these estimated proved reserves, 80% were proved developed and 97% were natural gas.  Our 2013 year-end reserve estimate decreased by 3.4 Bcfe after reductions for 2013 production and increases due to extensions and discoveries and revision of estimates.  We had positive revisions of 4.2 Bcfe due to the increase in natural gas prices used in the reserve estimate, as calculated in accordance with the Securities and Exchange Commission (“SEC”) pricing rules.   Pricing increased 38% from $2.56 per MMbtu for the year ended December 31, 2012, to $3.53 per MMbtu for the year ended December 31, 2013.  As a result of the higher pricing, certain of our undeveloped well locations on the Pinedale Anticline, which were excluded from our 2012 estimate, became economic.   The increase from the Pinedale Anticline reserves was offset in part by downward revisions in the reserve estimate at our non-operated Atlantic Rim properties.  The downward revision in the Atlantic Rim is a reflection of the lower production volumes from these properties in 2012 and 2013 due to operational challenges.  Our 2013 net production totaled 9.2 Bcfe.  

The proved oil and gas reserves at December 31, 2013 had a PV-10 value of approximately $78.2 million, an increase of 34% from December 31, 2012 primarily due to the increase in pricing noted above. The benefit realized from the increase in pricing was partially offset by a shift in the decline curve at our non-operated Atlantic Rim properties, which reduced the present value of the reserves.  (See the reconciliation of the PV-10 non-GAAP financial measure to the standardized measure under Reserves on page 8).

Developments since December 31, 2012

During 2013, we invested $9.6 million to continue to grow production and reserves in our core properties and for the Niobrara exploration project to pursue hydrocarbons in the Atlantic Rim.

Our 2013 capital program included the following:

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Challenges and opportunities

The exploration for, and the acquisition, development, production, and sale of natural gas and oil is highly competitive and capital intensive. As in any commodity business, the market price of the commodity produced and the costs associated with finding, acquiring, extracting, and financing the operation are critical to profitability and long-term value creation for stockholders.   Currently, our production is comprised of 98% natural gas, which heightens our exposure to the market volatility associated with natural gas. The market and future prices for natural gas began to rise slightly in late 2013; however, we will continue to focus on low cost production assets. If average natural gas prices decline or remain at low levels, it could reduce the value of our reserves, and thus the borrowing base of our credit facility. Generating reserve and production growth while containing costs is an ongoing focus for management, and is made particularly important in our business by the ongoing production and the reserve declines associated with oil and gas properties. We attempt to overcome these declines by drilling to find additional reserves, acquisitions of additional reserves and exploiting new exploration opportunities.  We may be required to raise additional funds to support our future drilling plans, which may be done through the issuance of additional shares of our common or preferred stock, or through additional borrowing under our credit facility. We have limited borrowing capacity under our current credit facility.  As of December 31, 2013, we had $47,450 outstanding under our credit facility and effective January 9, 2014, our borrowing base was reduced to $55,000 as a result of our October 1, 2013 borrowing base redetermination.  Our future growth will depend on our ability to continue to add reserves in excess of production.

Our ability to add reserves through drilling is dependent on our available capital resources but is also influenced by many other factors, including our ability to obtain drilling permits in a timely manner, the process involved in obtaining regulatory approvals and the ability to complete drilling operations within the applicable stipulated timeframe. The permitting and approval process has become increasingly difficult over the past several years due to an increase in regulatory requirements and increased activism from environmental and other groups, which has extended the time it takes us to receive permits, and other necessary approvals. Until recently, we had not encountered any significant delays in permit or drilling approvals in our core properties. However, in 2011 we experienced an increased time frame in obtaining the necessary permits to drill our exploratory well in the Atlantic Rim. In late 2012, we also received notification that an environmental group was appealing the Bureau of Land Management’s environmental impact assessment conducted in conjunction with permits issued in an undeveloped part of the Catalina Unit. Because of our relatively small size and concentrated operated property base, we can be at a disadvantage to our competitors by delays in obtaining or failing to obtain drilling approvals compared to companies with larger or more dispersed property bases. Our ability to shift drilling activities to areas where permitting may be easier is limited, and we have fewer properties over which to spread the costs related to complying with these regulations and the costs or foregone opportunities resulting from delays.

We also face challenges in attracting and retaining qualified personnel and third-party service providers, gaining access to equipment and supplies and maintaining access to capital on sufficiently favorable terms.

We have taken the following steps to mitigate the challenges we face:

Development and Exploration Outlook for 2014

We plan to expend up to $6,000 of capital for development drilling programs in 2014. Our 2014 program is focused on the Atlantic Rim projects below:

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At the Pinedale Anticline, the operator has completed drilling of the Mesa “B” PA and will focus its efforts for the next several years on the Mesa “A” PA, where we only have an overriding royalty interest and will not incur any capital costs.  

 

RESULTS OF OPERATIONS

The table below provides a year-to-year overview of selected reserve, production and financial information. The information contained in the table below should be read in conjunction with our consolidated financial statements and accompanying notes included in this Form 10-K.

 

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Year ended December 31, 2013 compared to the year ended December 31, 2012

The following analysis provides comparison of the year ended December 2013 and the year ended December 31, 2012.

Oil and gas sales, production volume and price comparisons

Oil and gas sales increased 20% to $31,784, primarily due to a 39% increase in the Colorado Interstate Gas (“CIG”) market price, which is the index on which most of our natural gas volumes are sold, offset in part by a 12% decrease in production volumes, which is discussed in more detail below.  Our average realized gas price increased 11% to $3.91 per Mcf.  In both 2013 and 2012, we realized natural gas prices that were higher than the prevailing market prices due to the derivatives we had in place. Our production volume is greater than our hedged volume, and therefore, we also realized a benefit from the increase in the CIG price in 2013.  

Our total net production decreased 12% to 9.2 Bcfe, primarily due to lower production volumes from the Atlantic Rim, as discussed in further detail below.

Our total average daily net production at the Atlantic Rim decreased 13% to 18,853 Mcfe. Our Atlantic Rim production comes from two operating units: the Catalina Unit and the Spyglass Hill Unit (which includes the Sun Dog, Doty Mountain, and Grace Point PAs). We operate the Catalina Unit and have non-operated working interests in the Spyglass Hill Unit.

 

Average daily net production on the Pinedale Anticline decreased 13% to 4,934 Mcfe due to normal production declines and operational challenges resulting from the cold weather in the fourth quarter of 2013.  The operator brought on 11 new wells in 2013, however, due to the location of these newer wells on the anticline, the additional production was not sufficient to offset the production decline from the existing wells  

Transportation and gathering revenue

We receive fees for gathering and transporting third-party gas through our intrastate gas pipeline, which connects the Catalina Unit with the interstate pipeline system owned by Southern Star. Transportation and gathering revenue decreased 25% to $3,745 due to the decrease in production volumes at the Catalina Unit discussed above. With additional compression, our pipeline is expected to have capacity of 125 MMcf per day, which is expected to be sufficient to handle transportation volumes from the development of the Catalina Unit and additional third party gas from other non-operated properties in the Atlantic Rim proximity.

 

Price risk management

We recorded a net loss on our derivative contracts not designated as cash flow hedges of $(730). This loss is a result of our hedging program used to mitigate our exposure to fluctuations in the natural gas price.  The net loss consisted of a realized gain of $6,185 related to the cash settlement of certain of derivative contracts, and an unrealized non-cash loss of $(6,915) which represents the change in the fair value on our derivative instruments at December 31, 2013.  The fair value of our unsettled derivative instruments will continue to change until the contracts are settled, and we will likely add to our hedging program. Therefore, we expect our results of operations to reflect the volatility of commodity price forward markets. Our cash flows will only be affected upon settlement of the transactions at the current market prices at that time.  See Item 15, Notes 1, 4, and 6 to the Notes to the Consolidated Financial Statements for discussion regarding the accounting treatment of our derivative contracts.

Other income

In 2009, we entered into an agreement that gave optional farm-in rights to a third party to re-enter the TTU #1 well located in the Main Fork Unit in Utah. We were notified in April 2013 that the third party was terminating the agreement and would not exercise its farm-in right. In accordance with the agreement, the third party paid us a termination penalty of $500. We are seeking a new partner for this property, and the BLM has conditionally approved us to temporarily abandon the property without plugging it at this time.    

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Oil and gas production expenses, production taxes, and depreciation, depletion and amortization

Well production costs increased 7% to $13,135, whereas production costs in dollars per Mcfe increased 22%, or $0.26 to $1.43 per Mcfe. The increase in total production costs is partially due to our increased working interest in the Atlantic Rim, which was effective for all of 2013, versus five months of 2012.  Also, we had higher transportation costs at the Spyglass Hill Unit, which was driven by the cost of natural gas, as power is generated by natural gas in the unit. The Spyglass Hill Unit, due to numerous drilling, completion and infrastructure difficulties, has a higher production cost per Mcfe rate as compared to the Catalina Unit. Because production from the Spyglass Hill made up a larger percentage of our total production during the year, we experienced an increase in production costs on a per Mcfe basis. Production costs on a per mcfe basis were higher also due to the decrease in production volumes, as a portion of our production costs are fixed or partially fixed.

Production taxes increased 30% to $3,906, and production taxes, on a dollars per Mcfe basis, increased 45%, or $0.13 to $0.42 per Mcfe. We are required to pay taxes on the proceeds received upon the physical sale of our gas to counterparties. Production taxes were higher in total and on a per Mcfe basis primarily due to the increase in the market prices for natural gas.

Total depreciation, depletion and amortization expenses (“DD&A”) increased 4% to $20,942, and depletion and amortization related to producing assets increased 4% to $20,560. Expressed in dollars per Mcfe, depletion and amortization related to producing assets increased 18% to $2.23.  Our depletion rate was higher in 2013 for the Catalina Unit, due to a decrease in our reserves, which were estimated to be lower in our year-end reserve report, primarily due to the decrease in pricing as calculated in accordance with SEC rules.  

Impairment and abandonment of equipment and properties

 

We continually evaluate our properties for potential impairment of value. During the year ended December 31, 2013, we recorded impairment expense of $4,812 related to the Niobrara exploration well completed in early 2013.  The well initially produced an encouraging amount of oil; however, subsequent production decreased significantly. The Company installed a pump on the well and attempted to regain oil production; however, we continue to recover injection fluid that was initially injected into the ground during the fracture stimulation stage of completion. While the well has not generated economically recoverable amounts of oil, the well is currently producing natural gas from the Niobrara formation and we are awaiting a permit that will allow it to begin producing natural gas from the Dakota and Frontier formations.  Management continues to evaluate oil production from this well, but due to our limited capital, further work thus far has been cost-prohibitive.  We had previously recorded impairment expense of $4,430 related to this well for the year ended December 31, 2012.  

 

 

Pipeline operating costs

Pipeline operating costs increased 6% to $5,194, primarily due to higher power charges.  

General and administrative

General and administrative (“G&A”) expenses decreased 13% to $5,395, primarily due to a $615 decrease in non-cash stock-based compensation expense resulting from lower expense related to our long term incentive plan (“LTIP”) adopted in 2011, as our executives did not achieve the performance-based metrics required for that portion of the award to vest, and also due to the forfeiture of shares by our former chief financial officer. Additionally, several executive stock grants fully vested at the end of 2012 and therefore we did not have any associated expense in 2013. Our salary and salary-related expenses decreased by $323, largely due to a reduction in headcount and lower executive bonuses.  

Deferred income taxes

During the year ended December 31, 2013, we recorded a deferred income tax benefit of $6,660. Our deferred income tax benefit reflects an effective book rate of 33.75% in 2013, which is lower than the 2012 rate primarily due to the impact of changes in certain state income tax rates on our deferred tax position. We expect to continue to generate losses for federal income tax reporting purposes, and anticipate net income from operations in future years, which has resulted in a deferred tax position reported under U.S. generally accepted accounting principles. We do not anticipate any significant required payments for current tax liabilities in the near future. We have estimated net operating loss carry-forwards (“NOLs”) of $59.0 million at December 31, 2013. We have evaluated the need to provide a valuation allowance on the amount recorded as the net operating loss carry-forward, and management has concluded that no valuation allowance is required as of December 31, 2013. In reaching this conclusion, management considered that we expect to generate income in excess of our NOLs by continuing to develop our core assets. In addition, we routinely consider the sale of non-core assets like our sale in 2012, which is likely to generate a tax gain, as the tax cost per Mcfe of our assets is generally lower than the current market rates being paid in the open market for gas producing properties. Our current NOLs do not begin to expire for eight years. Our assessment does not take into account any future impact of changes in tax laws.

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Year ended December 31, 2012 compared to the year ended December 31, 2011

The following analysis provides comparison of the year ended December 2012 and the year ended December 31, 2011.

Oil and gas sales, production volume and price comparisons

Oil and gas sales decreased 40% to $26,574, primarily due to a 32% decrease in the CIG price.  In addition, the decrease was partially due to the classification of our settlements on derivative instruments on the consolidated statement of operations. During the year ended December 31, 2011, one of our derivative instruments was classified as a cash flow hedge, and the settlements related to this contract totaling $9,592 were included within oil and gas sales. Whereas during the year ended December 31, 2012, all of our derivative instrument settlements were included within price risk management activities. The decrease in the natural gas market price was offset by a 13% increase in production volumes, discussed below.

As shown on the table on page 30, our average realized gas price decreased 24% to $3.52 due to the decrease in the CIG market price, offset by settlements of our derivative instruments during the period totaling $12,349.

Our total net production increased 13% to 10.5 Bcfe, primarily due to higher production volumes from the Atlantic Rim, discussed below.

Our total average daily net production at the Atlantic Rim increased 17% to 21,771 Mcfe. Our Atlantic Rim production comes from two operating units: the Catalina Unit and the Spyglass Hill Unit.

Average daily net production in the Pinedale Anticline increased 4% to 5,647 Mcfe as the operator brought 14 new wells on-line for production during 2012. Production from the new wells was partially offset by the normal production decline from existing wells in this field, particularly in the Mesa “C” Unit.

Transportation and gathering revenue

Transportation and gathering revenue increased 2% to $4,999, due to the increase in production volumes at the Catalina Unit discussed above.

 

Price risk management

We recorded a net gain on our derivative contracts not designated as cash flow hedges of $4,939. This consisted of an unrealized non-cash loss of $(7,410), which represents the change in the fair value on our economic hedges at December 31, 2012, and a net realized gain of $12,349 related to the cash settlement of certain of our economic hedges.

Other income

In the fourth quarter of 2012, we sold our interest in approximately 780 acres of non-core Wyoming properties for a gain of $1,640. In 2011, we recognized a gain of $371 when we sold 75% of our interest in our Nevada properties.

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Oil and gas production expenses, production taxes, and depreciation, depletion and amortization

Well production costs increased 11% to $12,299, whereas production costs in dollars per Mcfe decreased 1%, or $0.01, to $1.17 per Mcfe. The overall increase in production costs was driven primarily by increased production costs at the Catalina Unit due to higher compression, power and water hauling costs due to the addition of the 13 new wells completed in late 2011, as well as the increase in our working interest in the Unit. The increase at the Catalina Unit was partially offset by lower operating costs at the Spyglass Hill Unit. We believe the operating costs were lower in this unit due to the former operator decreasing maintenance-related expenditures as well as decreasing the overhead costs allocated to this unit, as it planned to sell these assets. Many of our operating costs at the Catalina Unit are fixed, and therefore production costs on a per Mcfe basis were lower due to the overall increase in production volumes.

Production taxes decreased 31% to $3,000, and production taxes, on a dollars per Mcfe basis, decreased 38%, or $0.18 to $0.29 per Mcfe. Production taxes were lower in total and on a per Mcfe basis primarily due to the decrease in the market prices for natural gas. In addition, we recorded an adjustment to production taxes related to allowable transportation deductions.

Total DD&A increased 7% to $20,216, and depletion and amortization related to producing assets increased 8% to $19,828. Expressed in dollars per Mcfe, depletion and amortization related to producing assets decreased 4% to $1.89, primarily due to a decrease in the depletion rate at the Catalina Unit for the first nine months of 2012. We calculate our fourth quarter DD&A expense using the year-end reserve report, which due to lower SEC pricing, reflected a decrease in reserves, and therefore our depletion rates in the fourth quarter of 2012 were higher than the first three quarters of 2012.

Exploration expenses, including dry hole costs

In the first quarter of 2012, we participated in drilling an exploratory well in the High Road Prospect near Gillette, Wyoming. The well reached total depth in February 2012 and the results of geological testing showed no economically producible hydrocarbons existed. We recorded $481 of dry hole expense related to this well.

Impairment and abandonment of equipment and properties

We recorded $4,430 of impairment expense related to our Niobrara exploration well in the fourth quarter of 2012.  For more discussion on this well, refer to page 31.  

Pipeline operating costs

Pipeline operating costs increased 19% to $4,892, primarily due to higher compression costs. In 2011, certain of our compressor leases were accounted for as capital leases with the related expense being recorded in DD&A. In 2012, all of our compressor leases were classified as operating leases.

 

General and administrative

G&A expenses increased 2% to $6,209, primarily due to a $188 increase in stock-based compensation.  In September 2011, we adopted the LTIP, under which our executive officers could earn shares of common stock for achieving certain service and performance targets. The increase in stock-based compensation is due to a full year of the expense related to the service condition being recorded in 2012 versus just one quarter of expense being recorded in 2011. We did not record any expense for the performance-based shares, as management did not expect the performance targets, as defined by the plan, to be met.  We also experienced an increase in salary and salary-related expense of $124. These increases were offset by a $124 decrease in bank fees.

Deferred income taxes

During the year ended December 31, 2012, we recorded a deferred income tax benefit of $5,418. Our deferred income tax benefit reflects an effective book rate of 34.31% in 2012, which is lower than the 2011 rate due to a decrease in permanent tax differences related to stock options.

LIQUIDITY AND CAPITAL RESOURCES

Our sources of liquidity and capital resources historically have been net cash provided by operating activities, funds available under our credit facilities and proceeds from offerings of equity securities. The primary uses of our liquidity and capital resources have been in the development and exploration of oil and gas properties. In the past, these sources of liquidity and capital resources have been sufficient to meet our needs and finance the growth of our business.

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We currently have a $150,000 revolving line of credit facility (the “Credit Facility”) in place with a $55,000 borrowing base.  At December 31, 2013, we had $47,450 outstanding on the Credit Facility. We expect that the current remaining availability of $7,550, coupled with our expected cash flow from operations will be sufficient to meet future financial covenants, maintain our current facilities, and complete our 2014 capital expenditure program (see “2014 Capital Spending Budget” on page 36).   

Our future success in growing proved reserves and production will be highly dependent on the capital resources available to us, natural gas prices and our success in finding or acquiring additional reserves.  As part of our strategy to grow our Company and increase shareholder value, we are actively seeking merger and acquisition opportunities, as well as pursuing the raising of additional capital.  The timing, structure, terms, size, and pricing of any such financing or transaction will depend on investor interest and market conditions.  We can provide no assurance that we will be able to do so on favorable terms or at all.  We may issue equity or debt in private placements or obtain additional debt financing, which may be secured by our oil and gas properties, or unsecured. We do not have any active registration statements with the SEC, and would therefore need to file a new registration statement to issue any additional registered equity, or we could issue unregistered shares through a private placement.    

Credit Facility

The Credit Facility is collateralized by our oil and gas producing properties and other assets. At December 31, 2013, we had $47,450 outstanding on the Credit Facility. We have depended on the Credit Facility over the past five years to supplement our operating cash flow in the development of the Company-operated Catalina Unit and other non-operated projects in the Atlantic Rim, including two purchases of additional working interest in this field, projects in the Pinedale Anticline, and the drilling of our Niobrara exploration well.

Borrowings under Credit Facility bear interest at a daily rate equal to the greater of (a) the Federal Funds rate, plus 0.5%, the Prime Rate or the Adjusted Eurodollar Rate plus (b) a margin ranging between 0.75% and 2.75% depending on the level of funds borrowed. The average interest rate on the facility at December 31, 2013, including the impact of our interest rate swaps, was 3.3%. We are subject to a variety of financial and non-financial covenants under the Credit Facility. As of December 31, 2013, we were in compliance with all covenants under the facility. If any of the covenants are violated, and we are unable to negotiate a waiver or amendment thereof, the lender would have the right to declare an event of default, terminate the remaining commitment, accelerate all principal and interest outstanding, and foreclose on our assets.

The determination of the borrowing base is made by the lenders at their sole discretion, semi-annually on April 1 and October 1.  Our lenders take into consideration the estimated value of our oil and gas properties based on pricing models determined by the lenders at such time, in accordance with the lenders’ customary practices for oil and gas loans. The available borrowing amount under the Credit Facility could increase or decrease based on such redetermination. An increase in our borrowing base would make additional funds available for our development activities and other uses. Alternatively, a decrease in our borrowing base would reduce the amount of funds available to us, or if the borrowing base were reduced below the then current outstanding Credit Facility balance, we would be required to repay such deficiency.  If such redetermination to the borrowing base were made, we may not have sufficient funds to make such required repayments or additional properties to pledge as collateral.  The last redetermination of the borrowing base occurred in October 2013 and resulted in a $5,000 reduction to the borrowing base. The next scheduled semi-annual redetermination of the borrowing base will occur on or about April 1, 2014.  

Capital Expenditures

Our primary capital expenditures by type for the years ended December 31, 2013 and 2012 were:

 

Year Ended December 31, 2013

In 2013, our capital spending was funded by operating cash flow and was focused on investment into our core properties, with investment in the Atlantic Rim properties and participation in drilling on the Pinedale Anticline.  At our Catalina Unit, we incurred $1,156, net to our interest, in costs to open up the Almond formation, which was previously unfractured, in 12 existing wells. At the Spyglass Hill unit, we incurred $2,445 in costs related to the drilling of 27 new wells.  

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On the Pinedale Anticline, we invested $3,498, net to our interest, in the drilling and completion of 11 new wells in the Mesa “B” PA. We are currently participating in the completion of one additional well, which was drilled in the second half of 2013, and is expected to come on-line for production in 2014.  Pending the completion of the one well, Mesa “B” will be drilled out.  The operator intends to move on to Mesa “A”, in which the Company holds an overriding royalty interest of 0.3125%.

We incurred costs of $1,396 during the year ended December 31, 2013 related to our Niobrara exploration well, which was spud in October 2011.  Completion was delayed by wildlife stipulations, and we had initial production in the first quarter of 2013.  The initial production results were encouraging, but subsequent production decreased quickly.  We installed a pump in the second quarter of 2013 in an attempt to regain production.  The well is currently producing gas from the Niobrara formation; however, the well has not generated economically recoverable amounts of oil.  The Company filed for a permit to comingle gas production from the Frontier, Dakota, and Niobrara formations produced from this well.  Upon approval, we expect to begin production of the Frontier and Dakota formations in August 2014.  

Year Ended December 31, 2012

In 2012, our capital spending centered on increasing our investment in our Atlantic Rim properties, participation in drilling at the Pinedale Anticline, and completion of our exploration well into the Niobrara formation in the Atlantic Rim.

On October 9, 2012, we exercised our preferential right to acquire additional working interest in the Catalina Unit and Spyglass Hill Unit from Anadarko for $4,874. We had previously signed an agreement with Anadarko to acquire 100% of Anadarko’s working interest in the Spyglass Hill and Catalina Units’ acreage; however, the joint operating agreements governing the Catalina and Spyglass Hill Units give preferential purchase rights to the other working interest owners in the event a working interest owner sells its assets. Warren, the other major owner in these units, exercised its preferential right, reducing the amount of additional working interest we acquired.

As a result of the purchase, the Company’s working interest increased as follows:

This purchase provided immediate production and at a lower cost than drilling new wells.

We also incurred capital costs of $8,864, net to our interest, in 2012 related to the Pinedale Anticline development, as we participated in the drilling and completion of 14 new wells in the Mesa Units. We also are currently participating in the drilling of 11 additional wells, which were drilled in the second half of 2012, and are expected to come on-line in 2013.

We also incurred $6,596 of the Niobrara exploration well’s total net cost of $12,158 in 2012.  

2014 Capital Spending Budget

We have budgeted $6 million for our capital projects in 2014, primarily for participation in 48 new wells in the Spyglass Hill Unit.  We also plan to swap out certain compressor equipment in the Catalina Unit, which will provide lower future operating costs.  We continue to evaluate acquisition and merger opportunities that we believe will complement our existing operations, increase our liquidity, offer economies of scale and/or provide further development, exploitation and exploration opportunities.

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Cash Flows

The table below provides a year-to-year overview of selected financial information that addresses our overall financial condition, liquidity, and cash flow activities. The information contained in the table below should be read in conjunction with our consolidated financial statements and accompanying notes included in this Form 10-K.

 

Net cash provided by operating activities

Operating activities provided cash of $13,082 in 2013, as compared to $19,468 in 2012 and $24,782 for 2011. The primary sources of cash during 2013 was a net loss of $(13,073), which was net of non-cash charges of $21,218 related to DD&A and accretion expense, $4,992 of impairment expense, and a $6,656 unrealized loss related to the change in fair value of our derivative contracts. This was offset by a decrease in stock-based compensation expense of $597, a tax benefit of $6,660 for deferred income taxes, and a decrease in accounts payable and accrued expenses.  Our 2013 cash flow includes cash of $500, which was paid to us by a third party as a penalty for terminating the farm-out agreement at the Main Fork Unit.

Our cash flow from operations for the year ended December 31, 2013 was lower, largely due to a decrease in production volumes of 12%, or 1.3 Bcfe.  This was partially offset by an increase in our average realized price, which increased approximately $0.42 per Mcfe.  

Net cash used in investing activities

Net cash used in investing activities was $(10,523) for 2013, as compared to $(25,773) in 2012 and $(23,946) in 2011. Our capital expenditures in 2013 were primarily related to participation in drilling and completion costs related to the Doty Mountain PA in the Spyglass Hill Unit, in which 27 wells were completed, drilling and completion costs related to 11 new wells on the Pinedale Anticline, our 2013 work over program in the Catalina Unit, and costs associated with our Niobrara exploration well.   

In 2012, our capital costs were primarily related to payment of drilling and completion costs related to our Niobrara exploration well, participation in development drilling in the Pinedale Anticline and our purchase of additional working interest in our Atlantic Rim properties for $4,874. In 2012, we also sold approximately 750 acres in a non-core Wyoming property for $1,640.

In 2011, we drilled 13 production wells and two injection wells in the Catalina Unit. We own a 100% working interest in twelve of the 13 production wells. We began drilling our Niobrara exploration well in the fourth quarter of 2011, although most of the costs were paid in 2012. Also in 2011, we sold 75% of our interest in our Nevada properties for cash proceeds of $371. We had impaired these properties in 2008, as we had no plans to develop the leases and there had been no oil and gas findings in the area. We retained a small overriding royalty interest in these Nevada properties.

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Net cash used in financing activities

Our financing activities used cash of $(3,830) in 2013, as compared to cash provided by financing activities of $1,697 and $5,237 in 2012 and 2011, respectively.  The cash used in financing activities in 2013 primarily related to the payment of dividends related to the Series A Preferred Stock as noted below. We drew down $5,450 on the Credit Facility in 2012, primarily to finance our purchase of additional working interest in the Atlantic Rim. In 2011, we drew down on our credit facility to finance our 2011 drilling program at the Catalina Unit. In each of the periods presented, we expended a total of $3,723 for dividends on our Series A Preferred Stock. We expect to continue to pay dividends on a quarterly basis on the Series A Preferred Stock at a rate of $931 per quarter. We may redeem the Series A Preferred Stock for cash at our option, in whole or from time to time in part, at a redemption price of $25.00 per share, plus accrued and unpaid dividends (whether or not earned or declared) to the redemption date. We would need to secure additional financing to complete such redemption to the extent that we could not fund such transaction using cash flows from operations.

Contractual Obligations

The following table summarizes our contractual obligations as of December 31, 2013:

 

 

The Company also has employment agreements in place with certain executive officers that, among other things, specify severance payments the executive officer would receive upon termination or a change in control of the Company.

Off-Balance Sheet Arrangements

We may enter into off-balance sheet arrangements and transactions that can give rise to off-balance sheet obligations, including operating lease arrangements, drilling contracts and undrawn letters of credit. We do not participate in transactions that generate relationships with unconsolidated entities or financial partnerships. Such entities are often referred to as structured finance or special purpose entities (“SPEs”) or variable interest entities (“VIEs”). SPEs and VIEs can be established for the purpose of facilitating off-balance sheet arrangements or other contractually narrow or limited purposes. We were not involved in any unconsolidated SPEs or VIEs at any time during any of the periods presented in this Annual Report on Form 10-K.

CONTRACTED VOLUMES

Derivative Instruments

We have entered into various derivative instruments to mitigate the risk associated with downward fluctuations in the natural gas price. Historically, these derivative instruments have consisted of forward contracts, swaps, and costless collars. The duration and size of our various derivative instruments varies, and depends on our view of market conditions, available contract prices and our operating strategy. Under our current credit agreement, we can hedge up to 90% of the projected proved developed producing reserves for the next 12 month period, and up to 80% of the projected proved producing reserves for the ensuing 24 month period.

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Our outstanding derivative instruments as of December 31, 2013 are summarized below:

 

 

See Item 15, Notes 1, 4, and 6 to the Notes to the Consolidated Financial Statements for discussion regarding the accounting treatment of our derivative contracts.

As with most derivative instruments, our derivative contracts contain provisions which may allow for another party to require security from the counterparty to ensure performance under the contract. The security may be in the form of, but not limited to, a letter of credit, security interest or a performance bond. Neither party in any of our derivative contracts has required any form of security guarantee as of December 31, 2013.

Interest rate swap

We have a $30 million fixed rate swap contract with a third party in place as a hedge against the floating interest rate on the Credit Facility. Under the hedge contract terms, we locked in the Eurodollar LIBOR portion of the interest calculation at approximately 1.050% for this tranche of our outstanding debt, which based on our current level of outstanding debt, translates to an interest rate on this tranche of approximately 3.55%. The contract is effective through September 30, 2016.

Other Volumes Contracted

We also have transportation and gathering agreement for all production volumes through our pipeline, for which we receive a third party fee per Mcf of gas transported.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

This discussion and analysis of our financial condition and results of operations are based on the consolidated financial statements prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). The preparation of our financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. Our significant accounting policies are described in Note 1, “Business Description and Summary of Significant Accounting Policies”, of the Notes to the Consolidated Financial Statements, included in Item 15 of this Annual Report on Form 10-K. In the following discussion, we have identified the accounting estimates that we consider as the most critical to aid in fully understanding and evaluating our reported financial results. Estimates regarding matters that are inherently uncertain require difficult, subjective or complex judgments on the part of our management. We analyze our estimates, including those related to oil and gas reserves, oil and gas properties, income taxes, contingencies and litigation, and base our estimates on historical experience and various other assumptions that we believe reasonable under the circumstances. Actual results may differ from these estimates.

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Successful Efforts Method of Accounting

We account for our natural gas and oil exploration and development activities utilizing the successful efforts method of accounting, which is one of two acceptable methods under GAAP. Under this method, costs of productive exploratory wells, development dry holes and productive wells, and undeveloped leases, and lease acquisition costs are capitalized. Exploration costs, including personnel costs, certain geological and geophysical expenses, and delay rentals for oil and gas leases are charged to expense as incurred. Exploratory drilling costs are initially capitalized but charged to expense if and when the well is determined not to have found reserves in commercial quantities. The sale of a partial interest in a proved property is accounted for as a cost recovery and no gain or loss is recognized as long as this treatment does not significantly affect the unit-of-production amortization rate. A gain or loss is recognized for all other sales of producing properties.

The application of the successful efforts method of accounting requires managerial judgment to determine the proper classification of wells designated as development or exploratory, which will ultimately determine the proper accounting treatment of the costs incurred. The results from a drilling operation can take considerable time to analyze and the determination that commercial reserves have been discovered requires both judgment and industry experience. Wells may be completed that are assumed to be productive and actually deliver oil and gas in quantities insufficient to be economic, which may result in the abandonment of the wells at a later date. Wells are drilled that have targeted geologic structures which are both development and exploratory in nature and an allocation of costs is required to properly account for the results. The evaluation of oil and gas leasehold acquisition costs may require managerial judgment to estimate the fair value of these costs with reference to drilling activity in a given area. Drilling activities in an area by other companies may also effectively condemn leasehold positions.

The successful efforts method of accounting can have a significant impact on the operational results reported when we are entering a new exploratory area in hopes of finding an oil and gas field that will be the focus of future development drilling activity. The initial exploratory wells may be unsuccessful and will be expensed.

Reserve Estimates

All of the reserve data in this Form 10-K are estimates. The estimates of our natural gas and oil reserves are projections made by qualified petroleum engineers in accordance with guidelines established by the SEC. In 2013, Netherland, Sewell & Associates, Inc. evaluated properties representing 99% of our reserves. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that are difficult to measure. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation and judgment. Uncertainties include the historical production from the area compared with production from other producing areas, the assumed effects of regulations by governmental agencies and assumptions governing future natural gas and oil prices, basis differentials, future operating costs, severance and excise taxes, development costs and workover costs, all of which may in fact vary considerably from actual results. In addition, economic producibility of reserves is dependent on the oil and gas prices used in the reserves estimate. Our reserves estimates are based on 12-month average commodity prices, unless contractual arrangements designate. For these reasons, estimates of the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, classifications of such reserves based on risk of recovery, and estimates of the future net cash flows expected there from may vary substantially.

Estimates of proved natural gas and oil reserves significantly affect our DD&A expense. For example, if estimates of proved reserves decline, the DD&A rate will increase, resulting in a decrease in net income. A decline in estimates of proved reserves could also cause us to perform an impairment analysis to determine if the carrying amount of our natural gas and oil properties exceeds fair value and could result in an impairment charge, which would reduce earnings. For purposes of depletion, depreciation, and impairment, reserve quantities are adjusted at all interim periods for the estimated impact of additions and dispositions.

Impairment of Long-Lived Assets

We review the carrying values of our oil and gas properties and undeveloped leaseholds, at least annually, or whenever events or changes in circumstances indicate that such carrying values may not be recoverable. If, upon review, the sum of the undiscounted pretax cash flows is less than the carrying value of the asset group, the carrying value is written down to estimated fair value. Individual assets are grouped for impairment review at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets, generally on a field-by-field basis. The fair value of impaired assets is determined based on quoted market prices in active markets, if available, or upon the present values of expected future cash flows. Cash flow estimates require forecasts and assumptions for many years into the future for a variety of factors, including commodity prices, operating and development costs and estimates of natural gas and oil reserves. Negative revisions in estimates of reserves quantities or expectations of falling commodity prices or rising operating or development costs could result in a reduction in undiscounted future cash flows and could indicate property impairment.

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We recorded non-cash impairment charges on properties included in developed properties of $4,962, $4,901, $0, for the years ended December 31, 2013, 2012 and 2011, respectively. During the years ended December 31, 2013 and 2012, our impairment charges included impairment expense of $4,812 and $4,430, respectively, related to our Niobrara exploration well.  We also wrote-off undeveloped leaseholds in the amount of $30, $87 and $187 for the years ended December 31, 2013, 2012 and 2011, respectively.

Asset Retirement Obligations

We recognize an estimated liability for future costs associated with the abandonment of our oil and gas properties. We base our estimate of the liability on our historical experience in abandoning oil and gas wells projected into the future based on our current understanding of federal and state regulatory requirements. Our present value calculations require us to estimate the economic lives of our properties, assume what future inflation rates apply to external estimates as well as determine what credit adjusted risk-free rate to use.

In periods subsequent to initial measurement of the asset retirement obligation (“ARO”), we recognize period-to-period changes in the liability resulting from the passage of time and revisions to either the timing or the amount of the original estimate of undiscounted cash flows. Revisions also result in increases or decreases in the carrying cost of the oil and gas asset. Increases in the ARO liability due to passage of time impact net income as accretion expense. The related capitalized cost, including revisions thereto, is charged to expense through production costs. The consolidated statement of operations impact of these estimates is reflected in our production costs and occurs over the remaining life of our oil and gas properties.

Derivative Instruments

We use derivative financial instruments to achieve a more predictable cash flow from our natural gas production and to protect us from cash-flow risks caused by declining commodity prices. All derivatives are measured at estimated fair value and recorded as liabilities or assets on the consolidated balance sheet. For derivative contracts that do not qualify, or for which we do not elect cash flow hedge accounting, changes in the estimated fair value of the contracts are recorded as unrealized gains and losses in the price risk management activities line item in the accompanying consolidated statement of operations. During 2011, one of our derivative instruments was designated as a cash flow hedge under which the change in fair value was recorded as a component of accumulated other comprehensive income and was subsequently reclassified into earnings as the contract settled.

We use our judgment to analyze which contracts meet the definition of a derivative instrument and to determine the fair value of each instrument identified. Changes in the estimated fair values of our mark-to-market derivative instruments reflect the volatility of the commodity price forward markets and will have a significant impact on our net income. For the year ended December 31, 2013, we reported a $(6,915) mark-to-market loss on commodity derivative instruments.

Fair Value of Measurements

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at measurement date and establishes a three level hierarchy for measuring fair value. In determining the fair value of our derivative instruments, we consider quoted market prices in active markets and quotes from counterparties, the credit rating of each counterparty, and our own credit rating.

In consideration of counterparty credit risk, we assessed the possibility of whether each counterparty to the derivative would default by failing to make any contractually required payments. Additionally, we consider our company to be of substantial credit quality and believe we have the financial resources and willingness to meet its potential repayment obligations associated with the derivative transactions.

Stock-Based Compensation

We measure and recognize compensation expense for all stock-based payment awards (including stock options and stock awards) made to employees and directors based on the estimated fair value at the grant date and recognize compensation expense in earnings over the requisite service period using a graded vesting method. Total stock-based compensation expense for equity-classified awards was $744 for the year ended December 31, 2013.

We use the Black-Scholes valuation model to determine the fair value of each stock option. Expected volatilities are based on the historical volatility of our stock over a period consistent with that of the expected terms of the options. The expected terms of the options are estimated based on factors such as vesting periods, contractual expiration dates, historical trends in our stock price and historical exercise behavior. The risk-free rates for periods within the contractual life of the options are based on the yields of U.S. Treasury instruments with terms comparable to the estimated option terms.

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We measure the fair value of the stock awards based upon the fair market value of our common stock on the date of grant and recognize any resulting compensation expense ratably over the associated service period, which is generally the vesting term of the stock awards. Certain awards contain a performance condition, which requires management to estimate the probability of vesting based upon actual and expected future results. We recognize these compensation costs net of a forfeiture rate, if applicable, and recognize the compensation costs for only those shares expected to vest. If our actual forfeiture rate is materially different from our estimate, the stock-based compensation expense could be different from what we have recorded in the current period.

Deferred income taxes

 

Deferred income tax assets and liabilities are recognized for the future income tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective income tax bases. Deferred income tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. Deferred income taxes are measured by applying currently enacted tax rates to the differences between financial statement and income tax reporting. We routinely assess the realizability of our deferred tax assets. If we conclude that it is more likely than not that some portion or all of the deferred tax assets will not be realized under accounting standards, the tax asset would be reduced by a valuation allowance. We consider estimated future taxable income in making such assessments. Numerous judgments and assumptions are inherent in the determination of future taxable income, including factors such as future operating conditions (particularly as related to prevailing natural gas prices). There can be no assurance that facts and circumstances will not materially change and require us to establish deferred tax asset valuation allowances in a future period.

 

7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Commodity Price Risks

Our major market risk exposure is in the pricing applicable to our natural gas and oil production. Pricing is primarily driven by the prevailing worldwide price for oil and spot market prices applicable to our U.S. natural gas production. Pricing for oil production and natural gas has been volatile and unpredictable for several years. The prices we receive for production depend on many factors outside of our control.

The primary objective of our commodity price risk management policy is to preserve and enhance the value of our equity gas production. We have entered into natural gas derivative contracts to manage our exposure to natural gas price volatility. Our derivative instruments typically consist of forward sales contracts, swaps and costless collars, which allow us to effectively “lock in” a portion of our future production of natural gas at prices that we consider favorable to us at the time we enter into the contract. These derivative instruments which have differing expiration dates, are summarized in the table presented above under Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Contracted Volumes.”

For the year ended December 31, 2013, our income before income taxes would have changed by $1,722 for each $0.50 change per Mcf in natural gas prices. Our income taxes would have increased $25 for each $1.00 change per Bbl in oil prices for the year ended December 31, 2013.

Interest Rate Risks

At December 31, 2013, we had a total of $47,450 outstanding under the Credit Facility ($55,000 borrowing base effective January 9, 2014). We pay interest on outstanding borrowings under our credit facility at interest rates that fluctuate based upon changes in our levels of outstanding debt and the prevailing market rates. Our average interest rate calculated in accordance with the agreement, was 3.3% at December 31, 2013. Assuming no change in the amount outstanding at December 31, 2013, the annual impact on interest expense for every 1.0% change in the average interest rate would be approximately $175 before taxes (including the impact of our interest rate swap). Any balance outstanding on the credit facility matures on October 24, 2016.

 

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

The information required by this item is included in Item 15, “Exhibits Financial Statements and Financial Statement Schedules.”

 

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

 

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ITEM 9A. CONTROLS AND PROCEDURES   

Evaluation of Disclosure Controls and Procedures

Our Chief Executive Officer and Chief Financial Officer have reviewed and evaluated the effectiveness of our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) as of the end of the period covered by this annual report on Form 10-K. Based upon this evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective in ensuring that material information required to be disclosed is included in the reports that we file with the Securities and Exchange Commission.

Management’s Annual Report on Internal Control Over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934. The Company’s internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with U.S. generally accepted accounting principles.

Management assessed the effectiveness of the our internal control over financial reporting as of December 31, 2013. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in the 1992 Internal Control-Integrated Framework. Based on this evaluation, our management concluded that our internal control over financial reporting was effective as of December 31, 2013.

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting during our fiscal quarter ended December 31, 2013 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

 

ITEM 9B. OTHER INFORMATION

None.

 

PART III

Pursuant to instruction G(3) to Form 10-K/A, the following Items 10,11,12,13 and 14 will be included Escalera Resources Co.’s definitive proxy statement for the 2014 annual meeting of stockholders filed on April 29, 2014 and is incorporated by reference to this report

 

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Code of Conduct and Ethics

We maintain a code of ethics applicable to our Board of Directors, principal executive officer, and principal financial officer, as well as all of our other employees. A copy of the Code of Business Conduct and Ethics and our whistleblower procedures may be found on our website at http://www.dble.com in the Corporate Governance section.

Revised biographies are provided here for certain directors of the Company.  The remaining disclosures are incorporated by reference from the definitive proxy statement for our 2014 annual meeting of stockholders filed on April 29, 2014.  

 

Susan G. Reeves, age 54, has been involved in the energy and financial services industries for over 25 years. Since 2004, she has served as president of Public Gas Partners (“PGP”), a non-profit company jointly owned by over 130 municipal gas distributors. PGP was created to secure economical, long-term wholesale natural gas supplies for its members. Under Ms. Reeves’ leadership, PGP has successfully closed 16 acquisitions consisting of more than 3,700 producing wells located in 12 states. Ms. Reeves has also served as the chief financial officer of the Municipal Gas Authority of Georgia (the “Gas Authority”) since 2002, where she oversees finance, accounting, risk management and information technology for the natural gas supplier. She is also responsible for all activities related to public debt offerings and is heavily involved in business development activities. Prior to her current roles with PGP and the Gas Authority, Ms. Reeves held a variety of leadership positions at eXchangeBridge, Inc., J.C. Bradford and Co., and Deloitte and Touche LLP. Ms. Reeves graduated from the University of Texas with highest honors and is a Certified Public Accountant in the State of Georgia.

Neil Bush, age 56, has been involved in both the energy industry and international business development for three decades. He began his career in 1980 with Amoco Production Company (now BP) in Denver, Colorado. Later in the 1980’s he formed two independent

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exploration and production companies that explored for oil in various locations, both domestically (Wyoming, Colorado, California, and Michigan) and internationally (Argentina).

 

Mr. Bush is the son of President and Mrs. George H.W. Bush, and he first visited China in 1976, following his father’s service as U.S. Chief Liaison Officer in Beijing. Since 1993 Mr. Bush has pursued international business development with a focus on Asia. He has engaged in different business activities in China including serving as Co-Chairman of CIIC, a privately held real-estate company with activities in Beijing, Hainan, and throughout China, from 2007 through current.  He often speaks in China to promote closer ties between China and the U.S.  Since 2013 Mr. Bush has served as the Chairman of SingHaiyi, a Singapore based publicly listed real-estate company that is actively investing in properties in the U.S.  Mr. Bush has also served as an independent director of Hoifu Energy, a Hong Kong listed energy company since 2012.  Mr. Bush graduated from Tulane University with a Bachelor of Science degree in International Economics and from the Tulane University Freeman School of Business with a Master’s degree in Business Administration. He serves as Chairman of Points of Light, Chairman of the Barbara Bush Houston Literacy Foundation, and serves on the boards of the Houston Salvation Army and the Bush School of Government and Public Service.

Charles Chambers, age 63, was appointed as the Chief Executive Officer of the Company in March 2014. In addition to serving as Chief Executive Officer (“CEO”), Mr. Chambers also serves as Chairman of the Board. Mr. Chambers has 40 years of experience in the upstream oil and gas business. From March 2012 to November 2013, he was Managing Director of Castleton Commodities International LLC’s Oil & Gas Business, responsible for managing upstream business activities with a focus on building a domestic natural gas properties portfolio.   From 2008 until March 2012, Mr. Chambers worked for Chambers Oil and Gas Inc, a company he founded, which sought oil and gas acquisition and investment opportunities.  From 2005 to 2008, Mr. Chambers held various positions at Rosetta Resources Inc., including CEO. Prior to Rosetta Resources Inc., Mr. Chambers served as Executive Vice President of Calpine Corporation and managed its acquisition efforts. Prior to joining Calpine, Mr. Chambers held positions at C&K Petroleum, Sheridan Energy and Grand Gulf Production.

 

 

ITEM 11. EXECUTIVE COMPENSATION

The executive compensation narrative included in the Company’s proxy statement filed with the SEC on April 29, 2014 includes reference to “clean earnings” as part of the Company annual cash bonus plan.  “Clean earnings" is a Company-defined non-GAAP metric which excludes the effects on net income of non-cash charges of depreciation, depletion and amortization expense, unrealized gains or losses related to the Company’s economic hedges, share-based compensation expense, the impact of income taxes and non-cash gains or losses related to property disposals (if any).  The remaining requirements of Item 11 are incorporated by reference from the definitive proxy statement for our 2014 annual meeting of stockholders filed on April 29, 2014.  

 

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

Equity Compensation Plans. The following table provides information as of December 31, 2013 with respect to shares of common stock that may be issued under our existing equity compensation plans. We have four active equity compensation plans—The 2002 Stock Option Plan, the 2003 Stock Option and Compensation Plan, the 2007 Stock Incentive Plan and the 2010 Stock Incentive Plan.

 

 

Information regarding beneficial ownership is incorporated by reference from the definitive proxy statement for our 2014 annual meeting of stockholders, which will be filed no later than 120 days after December 31, 2013.

 

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ITEM 13. CERTAIN RELATIONSHIPS, RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE

Incorporated by reference from the definitive proxy statement for our 2014 annual meeting of stockholders, which will be filed no later than 120 days after December 31, 2013.

 

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

Incorporated by reference from the definitive proxy statement for our 2014 annual meeting of stockholders, which will be filed no later than 120 days after December 31, 2013.

 

 

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PART IV

 

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a)(1) and (a)(2) Financial Statements and Financial Statement Schedules

 

All other schedules are omitted because the required information is not applicable or is not present in amounts sufficient to require submission of the schedule or because the information required is included in the Consolidated Financial Statements and Notes thereto.

(b) Exhibits. The following exhibits are filed with or incorporated by reference into this report on Form 10-K/A:

 

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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.

ESCALERA RESOURCES CO.

 

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.

 

 

 

 

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

 

 

 

To the Board of Directors and Stockholders

Escalera Resources Co.

 

 

We have audited the accompanying consolidated balance sheets of Escalera Resources Co. and subsidiaries as of December 31, 2013 and 2012, and the related consolidated statements of operations, stockholders’ equity, and cash flows for the years ended December 31, 2013, 2012 and 2011. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our 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. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

 

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Escalera Resources Co. and subsidiaries as of December 31, 2013 and 2012, and the results of their operations and their cash flows for the years ended December 31, 2013, 2012 and 2011, in conformity with U.S. generally accepted accounting principles.

 

 

 

 

Hein & Associates LLP

 

Denver, Colorado

March 13, 2014

 

 

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DOUBLE EAGLE PETROLEUM CO.

CONSOLIDATED BALANCE SHEETS

(Amounts in thousands of dollars except share and per share data)

 

 

The accompanying notes are an integral part of the consolidated financial statements.

 

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DOUBLE EAGLE PETROLEUM CO.

CONSOLIDATED STATEMENTS OF OPERATIONS

(Amounts in thousands of dollars except share and per share data)

 

 

 

 

 

The accompanying notes are an integral part of the consolidated financial statements.

 

 

 

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DOUBLE EAGLE PETROLEUM CO.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Amounts in thousands of dollars except share and per share data)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

The accompanying notes are an integral part of the consolidated financial statements.

 

 

 

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DOUBLE EAGLE PETROLEUM CO.

CONSOLIDATED STATEMENT OF CASH FLOWS

(Amounts in thousands of dollars)

 

 

The accompanying notes are an integral part of the consolidated financial statements.

 

 

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DOUBLE EAGLE PETROLEUM CO.

CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY

(Amounts in thousands of dollars except share data)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

The accompanying notes are an integral part of the consolidated financial statements.

 

 

 

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DOUBLE EAGLE PETROLEUM CO.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(Amounts in thousands of dollars except share and per share data)

 

Description of Operations

Double Eagle Petroleum Co. (“Double Eagle” or the “Company”) is an independent energy company engaged in the exploration, development, production and sale of natural gas and oil, primarily in the Rocky Mountain basins of the western United States. Double Eagle was incorporated in the State of Wyoming in January 1972 and reincorporated in the State of Maryland in February 2001.

Principles of Consolidation and Basis of Presentation

The consolidated financial statements include the accounts of the Company and its wholly-owned subsidiaries, Petrosearch Energy Corporation and Eastern Washakie Midstream Pipeline LLC (“EWM”). The Company has an agreement with EWM under which the Company pays a fee to EWM to gather, compress and transport gas produced at the Catalina Unit. This fee is also eliminated in consolidation.

The Company has no interests in any unconsolidated entities, nor does it have any unconsolidated special purpose entities.

Certain reclassifications have been made to amounts reported in previous years to conform to the 2013 presentation. Such reclassifications had no effect on net income.

Cash and Cash Equivalents

Cash and cash equivalents include all cash balances and any highly liquid investments with an original maturity of 90 days or less. The carrying amount approximates fair value due to the short maturity of these instruments.

Cash Held in Escrow

The Company has received deposits representing partial prepayments of the expected capital expenditures from third party working interest owners in the Table Top Unit #1 exploration project. The unexpended portion of the deposits at December 31, 2013 and 2012 totaled $283 and $565, respectively.

Accounts Receivable

The Company records estimated oil and gas revenue receivable from third parties at its net revenue interest. The Company also reflects costs incurred on behalf of joint interest partners in accounts receivable. Management periodically reviews accounts receivable amounts for collectability and records its allowance for uncollectible receivables under the specific identification method. The Company did not record any allowance for uncollectible receivables in 2013, 2012 or 2011.

Use of Estimates in the Preparation of Financial Statements

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of oil and gas reserves, assets and liabilities and disclosure on 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 those estimates. Estimates of oil and gas reserve quantities provide the basis for calculation of depletion, depreciation, and amortization, and impairment, each of which represents a significant component of the consolidated financial statements.

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Concentration of Market Risk

The future results of the Company’s operations will be affected by the market prices of natural gas.  Natural gas comprised approximately 98% of our total production for the year ended December 31, 2013 and represented 97% of our reserves as of December 31, 2013.  The market for natural gas in the future will depend on numerous factors beyond the control of the Company, including weather, imports, marketing of competitive fuels, proximity and capacity of oil and gas pipelines and other transportation facilities, any oversupply or undersupply of gas, the regulatory environment, the economic environment and other regional, national and international economic and political events, none of which can be predicted with certainty.

The Company operates in the exploration, development and production phase of the oil and gas industry. Its receivables include amounts due from the Company’s third party gas marketing company and amounts due from joint interest partners for their respective portions of operating expenses and exploration and development costs. Collectability is dependent upon the financial wherewithal of each counterparty as well as the general economic conditions of the industry. The receivables are not collateralized.

Concentration of Credit Risk

Financial instruments that potentially subject the Company to credit risk consist of accounts receivable and derivative financial instruments. The Company currently uses three counterparties for its derivative financial instruments. The Company continually reviews the credit worthiness of its counterparties, which are generally other energy companies or major financial institutions. In addition, the Company uses master netting agreements which allow the Company, in the event of default, to elect early termination of all contracts with the defaulting counterparty. If the Company chooses to elect early termination, all asset and liability positions with the defaulting counterparty would be “net settled” at the time of election. “Net settlement” refers to a process by which all transactions between counterparties are resolved into a single amount owed by one party to the other.

Revenue Recognition and Gas Balancing

The Company recognizes oil and gas revenues for its ownership percentage of total production under the entitlement method, whereby the working interest owner records revenue based on its share of entitled production, regardless of whether the Company has taken its ownership share of such volumes. An over-produced owner would record the excess of the amount taken over its entitled share as a reduction in revenues and a payable while the under-produced owner records revenue and a receivable for the imbalance amount. The Company’s imbalance position with various third party operators at December 31, 2013 resulted in an imbalance receivable of 115 MMcf, or $327, which is included in accounts receivable, net, on the consolidated statement of operations, and an imbalance payable of 241 MMcf, or $900, which is included in accounts payable and accrued expenses on the consolidated statement of operations.

Oil and Gas Producing Activities

The Company uses the successful efforts method of accounting for its oil and gas producing activities. Under this method of accounting, all property acquisition costs and costs of exploration and development wells are capitalized when incurred, pending determination of whether the well has found proved reserves. If an exploratory well does not find proved reserves in sufficient quantities to render the well economic, the costs of drilling the well are charged to expense. The costs of development wells are capitalized whether productive or nonproductive. The Company limits the total amount of unamortized capitalized costs for each property to the value of future net revenues, based on expected future prices and costs.

Geological and geophysical costs and the costs of carrying and retaining unproved leaseholds are expensed as incurred. Costs of production and general corporate activities are expensed in the period incurred.

Depreciation, depletion and amortization (“DD&A”) of capitalized costs for producing oil and gas properties is calculated on a field-by-field basis using the units-of-production method, based on proved oil and gas reserves. DD&A takes into consideration restoration, dismantlement and abandonment costs and the anticipated proceeds for equipment salvage. The Company has historically based the fourth quarter depletion calculation on the respective year end reserve report and used this methodology in computing the fourth quarter 2013 depletion expense.

DD&A of oil and gas properties for the years ended December 31, 2013, 2012 and 2011 was $20,560, $19,828 and $18,439, respectively.

The Company invests in unevaluated oil and gas properties for the purpose of future exploration and development of proved reserves. The costs of unproved leases which become productive are reclassified to proved properties when proved reserves are discovered on the property. Unproved oil and gas interests are carried at the lower of cost or estimated fair market value and are not subject to amortization.

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The following table reflects the net changes in capitalized exploratory well costs during the years ended December 31, 2013, 2012 and 2011. Amounts do not include costs capitalized and subsequently expensed in the same annual period.

 

 

Asset Retirement Obligations

Legal obligations associated with the retirement of long-lived assets result from the acquisition, construction, development and normal use of the asset. The Company’s asset retirement obligations relate primarily to the dismantlement, removal, site reclamation and similar activities associated with its oil and natural gas properties and related production facilities, lines and other equipment used in the field operations.

The initial estimated retirement obligation of properties is recognized as a liability with an associated increase in oil and gas properties for the asset retirement cost, and then depleted over the life of the asset.  The Company utilizes the income valuation technique to determine the fair value of the liability at the point of inception by taking into account (1) the cost of abandoning oil and gas wells, which is based on the Company’s historical experience for similar work, or estimates from independent third-parties; (2) the economic lives of its properties, which is based on estimates from reserve engineers; (3) the inflation rate; and (4) the credit adjusted risk-free rate, which takes into account the Company’s credit risk and the time value of money. Given the unobservable nature of the inputs, the initial measurement of the asset retirement obligation liability is deemed to use Level 3 inputs. The liability is periodically adjusted to reflect (1) new liabilities incurred; (2) liabilities settled during the period; (3) accretion expense and (4) revisions to estimated future cash flow requirements. For the years ended December 31, 2013, 2012 and 2011, an expense of $276, $188 and $174, respectively, was recorded as accretion expense on the liability and included in production costs on the consolidated statement of operations.

Impairment of Long-Lived Assets

The long-lived assets of the Company consist primarily of proved oil and gas properties and undeveloped leaseholds. The Company reviews the carrying values of its oil and gas properties and undeveloped leaseholds annually or whenever events or changes in circumstances indicate that such carrying values may not be recoverable. If, upon review, the sum of the undiscounted pretax cash flows is less than the carrying value of the asset group, the carrying value is written down to estimated fair value. Individual assets are grouped for impairment purposes at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets, generally on a field-by-field basis. The fair value of impaired assets is determined based on quoted market prices in active markets, if available, or upon the present values of expected future cash flows. The impairment analysis performed by the Company may utilize Level 3 inputs.

The Company recorded proved property impairment expense of $4,962, $4,901 and $0 for the years ended December 31, 2013, 2012 and 2011, respectively.  The impairment expense in 2013 and 2012, primarily related to its Niobrara exploration well.  The Company began drilling a well targeting the Niobrara, Dakota and Frontier formations in the fourth quarter of 2011.  Wyoming wildlife regulations prohibit drilling in this well location for approximately seven months of the year, which delayed our well completion and initial production until February 2013.  The Company exceeded its initial capital budget for the well due to challenges experienced during the drilling of the well, and the subsequent decision to complete the well in zones that were not initially planned for production.  The initial production results from the Niobrara formation were encouraging; however, subsequent production decreased significantly.  As a result, for the year ended December 31, 2012, the Company re-evaluated the well’s geology and recorded an initial impairment on the well of $4,430 based on expected future discounted net cash flows from the well.

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In 2013, the Company installed a pump on the well and attempted to regain oil production; however, the Company continues to recover injection fluid that was initially injected into the ground during the fracture stimulation stage of completion. While the well has not generated economically recoverable amounts of oil, the well is currently producing natural gas from the Niobrara formation and the Company is awaiting a permit that will allow it to begin producing natural gas from the Dakota and Frontier formations.  The Company anticipates receipt of this permit during 2014, and, subject to receipt of the permit, expects production from these formations to begin in the third quarter of 2014.  Management continues to evaluate oil production from this well, but due to its limited capital, further work thus far has been cost-prohibitive.  Based on the Company’s production results to date, management has updated it estimate of future net cash flow from this well, and recorded additional impairment expense of $4,812 for the year ended December 31, 2013.  The Company recognized a non-cash charge on undeveloped leaseholds during the years ended December 31, 2013, 2012 and 2011 of $30, $87 and $187, respectively.

The Company’s pipeline facilities are recorded at cost, which totaled $5,510 as of December 31, 2013. Depreciation is recorded using the straight-line method over a 25 year estimated useful life, and totaled $221 for the year ended December 31, 2013. The useful life may be limited to the useful life of current and future recoverable reserves serviced by the pipeline. The Company evaluated the expected useful life of the pipeline assets as of December 31, 2013, and determined that the assets are expected to be utilized for at least the estimated useful life used in the depreciation calculation.

Corporate and Other Assets

Office facilities, equipment and vehicles are recorded at cost. Depreciation is recorded using the straight-line method over the estimated useful lives of 10 to 40 years for office facilities, 3 to 10 years for office equipment, and 7 years for vehicles. Depreciation expense for the years ended December 31, 2013, 2012 and 2011 was $161, $167 and $186, respectively.

Major Customers

The Company had sales to one major unaffiliated gas marketing customer for the years ended December 31, 2013, 2012 and 2011 totaling $26,360, $23,145 and $22,159, respectively. No other single customer accounted for 10% or more of revenues in 2013, 2012 and 2011. Although a substantial portion of the Company’s production is purchased by one customer, the Company does not believe the loss of this customer would have a material adverse effect on the Company’s business as there are other gas marketers serving in the area where the Company operates.

Industry Segment and Geographic Information

The Company operates in one industry segment, which is the exploration, development, production and sale of natural gas and oil. All of the Company’s operations are conducted in the continental United States. Consequently, the Company currently reports as a single industry segment. The Company’s transportation and gathering subsidiary provides services exclusively for the company that markets its gas and all of the revenue generated by this subsidiary is primarily related to volumes produced from the Catalina Unit. Segmentation of such net income would not provide a better understanding of the Company’s performance, and is not viewed by management as a discrete reporting segment. However, gross revenue and expense related to the transportation and gathering subsidiary are presented as separate line items in the accompanying consolidated statement of operations.

Employee Benefit Plan

The Company maintains a Simplified Employee Pension Plan covering substantially all employees meeting minimum eligibility requirements. Employer contributions are determined solely at management’s discretion. Employer contributions for years ended 2013, 2012 and 2011 were $197, $226 and $221, respectively.

Income Taxes

Deferred income tax assets and liabilities are recognized for the future income tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective income tax bases. Deferred income tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred income tax assets and liabilities of a change in income tax rates is recognized in income in the period that includes the enactment date. The measurement of deferred income tax assets is reduced, if necessary, by a valuation allowance if management believes that it is more likely than not that some portion or all of the net deferred tax assets will not be fully realized on future income tax returns. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, available taxes in carryback periods, projected future taxable income and tax planning strategies in making this assessment.

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Earnings per Share

Basic earnings per share (“EPS”) is calculated by dividing net income (loss) attributable to common stock by the weighted average number of shares of common stock outstanding during the period. Diluted earnings per share incorporates the treasury stock method to measure the dilutive impact of potential common stock equivalents by including the effect of outstanding vested and unvested stock options and unvested stock awards in the average number of common shares outstanding during the period. Income attributable to common stock is calculated as net income less dividends paid on the Company’s Series A Preferred Stock. The Company declared and paid cash dividends of $3,723 ($.5781 per share of preferred stock) for each of the years ended December 31, 2013, 2012 and 2011.

The following table shows the calculation of basic and diluted weighted average shares outstanding and EPS for the periods indicated:

 

 

The following options and stock awards that could be potentially dilutive in future periods were not included in the computation of diluted net income (loss) per share because the effect would have been anti-dilutive for the periods indicated:

 

 

Stock-Based Compensation

The Company measures and recognizes compensation expense for all stock-based payment awards (including stock options and stock awards) made to employees and directors based on estimated fair value. Compensation expense for equity-classified awards is measured at the grant date based on the fair value of the award and is recognized as an expense in earnings over the requisite service period using a graded vesting method. Certain awards contain a performance condition, which is taken into account in estimating fair value.

Derivative Financial Instruments

The Company uses derivative instruments, primarily swaps and collars, to hedge risk associated with fluctuating commodity prices. The Company accounts for its derivatives instruments as mark-to-market instruments and are recorded at fair value and included in the consolidated balance sheets as assets or liabilities with changes in fair value recorded in earnings. See Notes 4 and 6 for additional discussion of derivative activities.

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Recently Adopted Accounting Pronouncements

In January 2013, the Financial Accounting Standards Board issued Accounting Standards Update No. 2013-01 (“ASU No. 2013-01”), ASU No. 2013-01 clarifies that the scope of Accounting Standards Update No. 2011-11, Disclosures about Offsetting Assets and Liabilities (“ASU No. 2011-11”), would apply to derivatives including bifurcated embedded derivatives, repurchase agreements and reverse repurchase agreements, and securities borrowing and securities lending transactions that are either offset or are subject to a master netting arrangement or similar agreement. ASU No. 2011-11, issued in December 2011, requires that entities disclose both gross and net information about instruments and transactions eligible for offset in the statement of financial position as well as instruments and transactions subject to an agreement similar to a master netting arrangement. In addition, the standard requires disclosure of collateral received and posted in connection with master netting agreements or similar arrangements. The Company adopted ASU No. 2013-01 effective January 1, 2013, and it did not have an effect on the Company’s consolidated financial statements.

 

As of December 31, 2013, the Company had a $150,000 revolving line of credit (“Credit Facility”) in place with a $60,000 borrowing base. Effective January 9, 2014, the borrowing base was reduced from $60,000 to $55,000 as a result of its October 1, 2013 borrowing base redetermination.  The Credit Facility is collateralized by the Company’s oil and gas producing properties. Any balance outstanding on the credit facility is due October 24, 2016.

As of December 31, 2013, the balance outstanding of $47,450 on the credit facility has been used to fund the development of the Catalina Unit and other non-operated projects in the Atlantic Rim, development projects in the Pinedale Anticline, and the Company’s Niobrara exploration project.

Borrowings under the Credit Facility bear interest at a daily rate equal to (a) the highest of the Federal Funds rate, plus 0.5%, the Prime Rate or the Adjusted Eurodollar Rate plus (b) a margin ranging between 0.75% and 2.75% depending on the level of funds borrowed. The average interest rate on the facility at December 31, 2013, including the impact of our interest rate swaps, was 3.3%. For the years ended December 31, 2013, 2012 and 2011, the Company incurred interest expense on the credit facility of $1,635, $1,275 and $1,070, respectively. Of the total interest incurred, the Company capitalized interest costs of $80, $321 and $155 for the years ended December 31, 2013, 2012 and 2011, respectively.

Under the Credit Facility, the Company is subject to both financial and non-financial covenants. The financial covenants, as defined in the credit agreement, include maintaining (i) a current ratio of 1.0 to 1.0; (ii) a ratio of earnings before interest, taxes, depreciation, depletion, amortization, exploration and other non-cash items (“EBITDAX”) to interest plus dividends of greater than 1.5 to 1.0; and (iii) a funded debt to EBITDAX ratio of less than 3.5 to 1.0. As of December 31, 2013, the Company was in compliance with all financial and non-financial covenants. If the covenants are violated and the Company is unable to negotiate a waiver or amendment thereof, the lenders would have the right to declare an event of default, terminate the remaining commitment and accelerate all principal and interest outstanding.

 

The following table reflects a reconciliation of the Company’s asset retirement obligation liability:

 

 

 

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Commodity Contracts

The Company’s primary market exposure is to adverse fluctuations in the price of natural gas. The Company uses derivative instruments, primarily costless collars and swaps, to manage the price risk associated with its gas production, and the resulting impact on cash flow, net income and earnings per share. The Company does not use derivative instruments for speculative purposes.

The extent of the Company’s risk management activities is controlled through policies and procedures that involve senior management and were approved by the Company’s Board of Directors. Senior management is responsible for proposing hedging recommendations, executing the approved hedging plan, overseeing the risk management process including methodologies used for valuation and risk measurement and presenting policy changes to the Company’s Board of Directors. The Company’s Board of Directors is responsible for approving risk management policies and for establishing the Company’s overall risk tolerance levels. The duration of the various derivative instruments depends on senior management’s view of market conditions, available contract prices and the Company’s operating strategy. Under the Company’s credit agreement, the Company can hedge up to 90% of the projected proved developed producing reserves for the next 12-month period, and up to 80% of the projected proved developed producing reserves for the 24-month period thereafter.

The Company accounted for all of its derivative instruments as mark-to-market derivative instruments in 2013 and 2012. Under mark-to-market accounting, derivative instruments are recognized as either assets or liabilities at fair value on the Company’s consolidated balance sheets and changes in fair value are recognized in the price risk management activities line on the consolidated statements of operations. Realized gains and losses resulting from the contract settlement of mark-to-market derivatives also are recorded in the price risk management activities line on the consolidated statements of operations.

In 2011, the Company had one derivative instrument that was accounted for as a cash flow hedge. Derivative instruments that are designated and qualify as cash flow hedges are recorded at fair value on the consolidated balance sheets, and the effective portion of the change in fair value is reported as a component of accumulated other comprehensive income (“AOCI”) and is subsequently reclassified into oil and gas sales on the consolidated statements of operations as the contracts settle. The last derivative instrument that the Company accounted for under cash flow hedge accounting settled in December 2011.

On the consolidated statements of cash flows, the cash flows from the derivative instruments are classified as operating activities.

The terms of the Company’s derivative instruments outstanding at December 31, 2013 are summarized as follows:

 

 

Interest Rate Swap

The Company has a $30 million fixed rate swap in place to manage the risk associated with the floating interest rate on its credit facility. Refer to Note 4 for a detailed breakout of the contract terms. Under the interest rate swap terms, the Company swapped its floating LIBOR interest rate for a fixed LIBOR interest rate. These contracts were not designated as fair value hedges or cash flow hedges and are recorded at fair value on the consolidated balance sheets. Changes in fair value, both realized and unrealized, are recognized in interest expense, net on the consolidated statements of operations. On the consolidated statements of cash flows, the cash flows from the interest rate swap are classified as operating activities.

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As of December 31, 2013, the Company had the following interest rate swap in place with a third party to manage the risk associated with the floating interest rate on the Credit Facility:

 

 

Impact of Derivatives on the Balance Sheet and Consolidated Statement of Operations

The table below contains a summary of all the Company’s derivative positions reported on the consolidated balance sheet as of December 31, 2013 and December 31, 2012, presented gross of any master netting arrangements:

 

 

The before-tax effect of derivative instruments in cash flow hedging relationships on the consolidated statement of operations for the years ended December 31, 2013, 2012 and 2011 was as follows:

 

 

 

¹ Not applicable as the Company did not have any cash flow hedges in the years ended December 31, 2013 and 2012.  

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The before-tax effect of derivative instruments not designated as hedging instruments on the consolidated statement of operations for the years ended December 31, 2013, 2012 and 2011 was as follows:

 

² Included in price risk management activities, net on the consolidated statements of operations. Price risk management activities totaled $(730), $4,939 and $14,740, for the years ended December 31, 2013, 2012 and 2011, respectively.

³ Included in interest expense, net on the statements of operations.

Refer to Note 6 for additional information regarding the valuation of the Company’s derivative instruments.

 

    

The tax effects of temporary differences that gave rise to the deferred tax liabilities and deferred tax assets as of December 31, 2013 and 2012 were:

 

 

In assessing the realizability of the deferred tax assets, management considers whether it is more likely than not that some or all of the deferred tax assets will not be realized. The ultimate realization of the deferred tax assets is dependent upon the generation of future taxable income during the periods in which the use of such net operating losses are allowed. Among other items, management considers the scheduled reversal of deferred tax liabilities, tax planning strategies and projected future taxable income. At December 31, 2013, the Company had a net operating loss carry forward for regular income tax reporting purposes of approximately $59.0 million, which will expire beginning in 2021.

The following table shows the reconciliation of the Company’s effective tax rate to the expected federal tax rate for the years ended December 31, 2013 and 2012:

 

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In accordance with the FASB’s Accounting Standards Codification (“ASC”) 740, Income Taxes, tax effects from any uncertain tax positions are recognized in the financial statements only if the position is more likely than not of being sustained if the position were to be challenged by a taxing authority. The Company has not recorded any liabilities, or interest and penalties, as of December 31, 2013 related to uncertain tax positions.

The Company files income tax returns in the U.S. and various state jurisdictions. The Company are currently has no federal or state income tax examinations underway for any of 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 2010 and for state and local tax authorities for years before 2009.

 

Assets and Liabilities Measured on a Recurring Basis

The Company’s financial instruments, including cash and cash equivalents, accounts receivable and accounts payable are carried at cost, which approximates fair value due to the short-term maturity of these instruments. The recorded value of the Company’s Credit Facility also approximates fair value as it bears interest at a floating rate.

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The FASB has established a three-level valuation hierarchy has been established to allow readers to understand the transparency of inputs in the valuation of an asset or liability as of the measurement date. The three levels are defined as follows:

Level 1 - Quoted prices (unadjusted) for identical assets or liabilities in active markets.

Level 2 - Quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, and model-derived valuations whose inputs or significant value drivers are observable.

Level 3 - Unobservable inputs that reflect the Company’s own assumptions.

The following tables provide a summary of assets and liabilities measured at fair value on a recurring basis as of December 31, 2013 and 2012:

 

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The Company did not have any transfers of assets or liabilities between Level 1, Level 2 or Level 3 of the fair value measurement hierarchy during the year ended December 31, 2013.

The following methods and assumptions were used to estimate the fair values of the assets and liabilities in the table above:

Derivative instruments

The Company determines its estimate of the fair value of derivative instruments using a market approach based on several factors, including quoted prices in active markets, market-corroborated inputs, such as NYMEX forward-strip pricing, the credit rating of each counterparty, and the Company’s own credit rating.

In consideration of counterparty credit risk, the Company assessed the possibility of whether each counterparty to the derivative would default by failing to make any contractually required payments. Additionally, the Company considers that it is of substantial credit quality and has the financial resources and willingness to meet its potential repayment obligations associated with the derivative transactions.

As of December 31, 2013, the Company had various types of derivative instruments, which included costless collars and swaps. The natural gas derivative markets and interest rate swap markets are highly active. Although the Company’s economic hedges are valued using public indices, the instruments themselves are traded with third party counterparties and are not openly traded on an exchange. As such, the Company has classified these instruments as Level 2.

Assets and Liabilities Measured on a Non-recurring Basis

The Company utilizes fair value on a non-recurring basis to perform impairment tests as required on its property and equipment. The inputs used to determine such fair value are primarily based upon internally developed cash flow models and would generally be classified within Level 3. Please refer to Note 1 for additional information regarding the Company’s impairment analysis for the year ended December 31, 2013.

The following table provides a summary as of December 31, 2013 of assets measured at fair value on a nonrecurring basis:

 

 

 

In 2007, the Company’s stockholders approved an amendment to the Company’s Articles of Incorporation to provide for the issuance of 10,000,000 shares of preferred stock, and the Company subsequently completed a public offering of 1,610,000 shares of 9.25% Series A Cumulative Preferred Stock (the “Series A Preferred Stock”) at a price of $25.00 per share.

Holders of the Series A Preferred Stock are entitled to receive, when and as declared by the Company’s Board of Directors, dividends at a rate of 9.25% per annum ($2.3125 per annum per share). The Series A Preferred Stock does not have any stated maturity date and will not be subject to any sinking fund or mandatory redemption provisions except, under certain circumstances, upon a change of ownership or control. The Company may redeem the Series A Preferred Stock for cash at its option, in whole or from time to time in part, at a redemption price of $25.00 per share, plus accrued and unpaid dividends (whether or not earned or declared) to the redemption date.

The shares of Series A Preferred Stock are classified outside of permanent equity on the consolidated balance sheets due to the change of control redemption provision applicable to such shares. Following a change of ownership or control of the Company by a person or entity in which the common stock of the Company is no longer traded on a national exchange, the Company will be required to redeem the Series A Preferred Stock within 90 days after the date on which the change of ownership or control occurred for cash. In the event of liquidation, the holders of the Series A Preferred Stock will have the right to receive $25.00 per share, plus all accrued and unpaid dividends, before any payments are made to the holders of the Company’s common stock.

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Holders of the Series A Preferred Stock generally have no voting rights. However, if cash dividends on any outstanding Series A Preferred Stock are in arrears for any six consecutive or non-consecutive quarterly dividend periods, or if the Company fails to maintain a national market listing, the holders of the Series A Preferred Stock, voting separately as a class, will have the right to elect two directors to serve on the Company’s Board of Directors in addition to those directors then serving on the Board until such time as the national market listing is obtained or the dividend arrearage is eliminated.

          

The Company has outstanding stock options issued to employees under various stock option plans, approved by the Company’s stockholders (collectively the “Plans”). Options granted under the Plans have been granted with an exercise price equal to the market price of the Company’s common stock on the date of grant, vest annually over various periods from two to five years of continuous service, and expire over various periods up to ten years from the date of grant. As of December 31, 2013, there were 24,971 and 39,998 options available for grant under the 2002 and 2003 Stock Option Plans, respectively.

The Company’s stockholders have also approved the 2007 Stock Incentive Plan (“2007 Plan”) and the 2010 Stock Incentive Plan, (“2010 Plan”), which allow both stock options and stock awards to be granted to the Company’s employees, directors, consultants, and other persons designated by the Compensation Committee of the Board of Directors. In 2008, the Company began granting stock awards and stock options under these plans. These awards vest annually over various periods of up to five years of continuous service. As of December 31, 2013, there were 424,409 and 388,508 shares available for grant under the 2007 and 2010 Plans, respectively.

The Company accounts for its stock compensation in accordance with the provisions of ASC 718, Compensation – Stock Compensation , which requires the measurement and recognition of compensation expense for all stock-based payment awards (including stock options and stock awards) made to employees and directors based on estimated fair value. During the years ended December 31, 2013, 2012 and 2011, total stock-based compensation expense for equity-classified awards, was $744, $1,341 and $1,153, respectively, and is reflected in general and administrative expense in the consolidated statements of operations.

Stock Options

The Company uses the Black-Scholes valuation model to determine the fair value of each option award. Expected volatilities are based on the historical volatility of the Company’s common stock over a period consistent with that of the expected terms of the options. The expected terms of the options are estimated based on factors such as vesting periods, contractual expiration dates, historical trends in the Company’s common stock price and historical exercise behavior. The risk-free rates for periods within the contractual life of the options are based on the yields of U.S. Treasury instruments with terms comparable to the estimated option terms.

The assumptions used in estimating the fair value of stock-options granted were:

 

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Summary of option activity during the year ended December 31, 2013:

 

No stock options were granted in 2013 or 2012. The weighted average grant date fair value price per share of options granted during the year ended December 31, 2011 was $2.65. No stock options exercised in 2013 and 2012. During the year ended December 31, 2011, the total intrinsic value, or the difference between the exercise price and the market price on the date of exercise, of all options exercised was $9. The Company issues new shares from its reserve upon exercise. As of December 31, 2013, 2012 and 2011, the intrinsic value of options vested and exercisable was $0, $0 and $89, respectively.

Stock options outstanding and currently exercisable at December 31, 2013 were as follows:

 

 

As of December 31, 2013, there was $21 of total unrecognized stock-based compensation expense related to stock options to be recognized over a weighted-average period of 1.2 years.

Stock Awards

The Company measures the fair value of the stock awards based upon the fair market value of its common stock on the date of grant and recognize the resulting compensation expense ratably over the associated service period, which is generally the vesting term of the stock awards. The Company recognizes these compensation costs net of a forfeiture rate, if applicable, and recognizes the compensation costs for only those shares expected to vest. The forfeiture rates are based on historical experience, while also considering the duration of the vesting term of the award.

Nonvested stock awards as of December 31, 2013 and changes for the year ended December 31, 2013 were as follows:

 

 

As of December 31, 2013, there was $132 of unrecognized stock-based compensation expense related to nonvested stock awards. This cost is expected to be recognized over a weighted-average period of 0.7 years.  The intrinsic value of restricted stock awards vested was $642, $372 and $457 for the years ended December 31, 2013, 2012 and 2011, respectively.  

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Long-Term Incentive Plan

In the fourth quarter of 2011, the Company adopted a Long-Term Incentive Plan (“LTIP”), under which the executive officers of the Company could earn shares for both continuous employment (one-third of the total shares) and through increases in the Company’s adjusted net asset value, as defined in the LTIP (two-thirds of the total shares). On December 31, 2013, 135,421 shares vested due to the continuous employment of its executive officers. The Company did not meet the minimum performance objectives as determined by the LTIP, and therefore no performance-based shares vested at December 31, 2013. The total compensation expense recorded by the Company related to the LTIP was $317, $462 and $161 for years ended December 31, 2013, 2012 and 2011, respectively. The nonvested stock awards table above includes the activity related to the Company’s LTIP.  

On January 1, 2014, the Company granted 181,903 shares to the certain of its executive management.  The shares will vest upon a change of control that is consummated and becomes effective on or before December 31, 2014. The shares issued under the award agreements will be subject to additional forfeiture restrictions, including the requirement that the executive’s employment has not terminated prior to the date of a change in control.

 

Operating Lease Commitments

The Company has entered into an operating lease through November 2015 for approximately 7,470 square feet of office space in Denver, Colorado. The Company also maintains operating leases various pieces of office equipment in both the Casper and Denver offices. The total annual minimum lease payments for the next five years and thereafter are:

 

 

The Company also leases certain compressor equipment in the Catalina Unit on a short-term basis of 12 months or less.  

Total expense from operating leases totaled $2,634, $2,888 and $2,049 in 2013, 2012 and 2011, respectively.

Litigation and Contingencies

From time to time, the Company is involved in various legal proceedings, which are subject to the uncertainties inherent in any litigation. The Company is defending itself vigorously in all such matters, and while the ultimate outcome and impact of any proceeding cannot be predicted with certainty, management believes that the resolution of any proceeding will not have a material adverse effect on the Company’s financial condition or results of operations.

 

On October 9, 2012, the Company exercised its preferential right to acquire additional working interest in the Catalina Unit and Spyglass Hill Unit (which includes the former Sun Dog and Doty Mountain Units) from Anadarko Petroleum Corporation (“Anadarko”). The Company had previously signed an agreement with Anadarko to acquire 100% of Anadarko’s working interest in the Spyglass Hill and Catalina Units’ acreage; however, the joint operating agreements governing the Catalina and Spyglass Hill Units give preferential purchase rights to the other working interest owners in the event a working interest owner sells its assets. The other major owner in these units exercised its preferential right, reducing the amount of additional working interest acquired by the Company. The purchase expanded the Company’s presence in one of its core development areas. The effective date of this transaction was August 1, 2012.

The following table summarizes the working interest acquired as a result of the transaction, and the Company’s post-transaction total ownership in each of the participating areas.

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The 2012 acquisition of working interest was accounted for under the purchase method of accounting. Under the purchase method of accounting, the purchase price of $4,874 is allocated to the assets acquired and liabilities assumed based on their estimated fair values. The final purchase price allocation was as follows:

Amounts recognized for final fair value of assets acquired and liabilities assumed:

 

 

The Company utilized the income approach to estimate the fair value of the properties and used discounted cash flow model that took into account the following inputs to arrive at estimates of future net cash flows: (1) estimated recovery of natural gas and oil as prepared by a third party engineering firm; (2) estimate of future commodity prices as of the acquisition date; (3) estimated future production rates and decline curves; and (4) estimated timing and amounts of future operating and development costs. The Company then applied a market-based discount rate to the future net cash flows that took in to consideration factors such as non-operatorship in the Spyglass Hill Unit, the unique operating agreements in this area and the low-pricing environment for dry Rockies natural gas. Due to the unobservable nature of the inputs, the fair values of the proved and unproved oil and gas properties are considered Level 3 fair value measurements.

 

Capitalized Costs Relating to Oil and Gas Producing Activities

The aggregate amount of capitalized costs relating to oil and natural gas producing activities and the aggregate amount of related accumulated depreciation, depletion and amortization at December 31, 2013, 2012 and 2011 were:

 

 

Costs Incurred in Oil and Gas Property Acquisitions, Exploration and Development Activities

Costs incurred in property acquisitions, exploration, and development activities for the years ended December 31, 2013, 2012 and 2011 were:

 

 

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Results of Operations from Oil and Gas Producing Activities

The table below shows the results of operations for the Company’s oil and gas producing activities for the years ended December 31, 2013, 2012 and 2011. All production is from within the continental United States.

 

Oil and Gas Reserves (Unaudited)

The reserves at December 31, 2013, 2012 and 2011 presented below were reviewed by the independent engineering firm, Netherland, Sewell & Associates, Inc. All reserves are located within the continental United States. The reserve estimates are developed using geological and engineering data and interests and burden information developed by the Company. Reserve estimates are inherently imprecise and are continually subject to revisions based on production history, results of additional exploration and development, prices of oil and gas, and other factors.

Estimated net quantities of proved developed and proved undeveloped reserves of oil and gas for the years ended December 31, 2013, 2012 and 2011 are:

 

 

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The following table summarizes the changes in our proved reserves for the years ended December 31, 2013, 2012 and 2011:

 

 

At December 31, 2013, the Company had net positive revisions of 4.2 Bcfe, which resulted from an increase of 43.9 Bcfe due to pricing revisions, offset in part, by decreases resulting from technical revisions of 39.7 Bcfe.   Pricing increased 38% from $2.56 per MMbtu for the year ended December 31, 2012, to $3.53 per MMbtu for the year ended December 31, 2013. As a result of the higher pricing, certain of our undeveloped well locations on the Pinedale Anticline, which were excluded from our 2012 estimate, became economic. The negative technical revisions made reflected the well performance of its Atlantic Rim properties in 2012 and 2013.  

 

At December 31, 2012, the Company revised its proved reserves downward by 61.8 Bcfe primarily due to a significant decline in the adjusted natural gas price used in the estimate, which decreased 40% from $3.73 per MMbtu to $2.24 per MMbtu. The decrease in the natural gas price resulted in 47.8 Bcf of proved undeveloped reserves included in our 2011 reserve estimate becoming uneconomic. Additionally, the Company purchased 13.4 Bcfe of additional reserves in the Atlantic Rim.  

 

At December 31, 2011, the Company had extensions and discoveries totaling 31.7 Bcfe of reserves as the result of drilling in the Catalina Unit in the Atlantic Rim and on the Pinedale Anticline.

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves (Unaudited)

The following information has been developed utilizing procedures prescribed by ASC 932 Extractive Activities – Oil and Gas, and is based on natural gas and oil reserves and production volumes estimated by the Company. It may be useful for certain comparison purposes, but should not be solely relied upon in evaluating the Company or its performance. Further, information contained in the following table should not be considered as representative or realistic assessments of future cash flows, nor should the Standardized Measure of Discounted Future Net Cash Flows be viewed as representative of the current value of the Company.

The Company believes that the following factors should be taken into account in reviewing the following information: (1) future costs and selling prices will likely differ from those required to be used in these calculations; (2) due to future market conditions and governmental regulations, actual rates of production achieved in future years may vary significantly from the rate of production assumed in these calculations; (3) selection of a 10% discount rate, as required under the accounting codification, is arbitrary and may not be reasonable as a measure of the relative risk inherent in realizing future net oil and gas revenues; and (4) future net revenues may be subject to different rates of income taxation.

Under the Standardized Measure, future cash inflows were estimated by applying the 12-month average pricing of oil and gas relating to the Company’s proved reserves to the year-end quantities of those reserves. Future cash inflows were reduced by estimated future development and production costs based upon year-end costs in order to arrive at net cash flow before tax. Future income tax expense has been computed by applying year-end statutory rates to future pretax net cash flows and the utilization of net operating loss carry-forwards.

Management does not rely solely upon the following information to make investment and operating decisions. Such decisions are based upon a wide range of factors, including estimates of probable, as well as proved reserves, and varying price and cost assumptions considered more representative of a range of possible economic conditions that may be anticipated.

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Information with respect to the Company’s Standardized Measure is as follows:

 

 

Principal changes in the Standardized Measure for the years ended December 31, 2013, 2012 and 2011 were as follows:

 

 

 

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The following table contains a summary of the unaudited financial data for each quarter for the years ended December 31, 2013 and 2012 (in thousands except per share data):

 

 

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