UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-K

 

☒ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2014 

☐TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

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  ☒ 

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  ☒ 

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  ☒    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  ☒    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  ☒ 

The aggregate market value of the voting common stock held by non-affiliates of the registrant at the close of business on June 30, 2014, was $34,351,704 (directors and officers are considered affiliates).

The number of shares of the registrant’s common stock outstanding as of April 3, 2015 was 14,279,450. 

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant’s definitive proxy statement for the 2015 annual meeting of stockholders, which will be filed within 120 days after December 31, 2014, are incorporated by reference in Part III of this Form 10-K.

 

 

 

 

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ESCALERA RESOURCES CO.

FORM 10-K

TABLE OF CONTENTS 

 

 

 

 

 

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Cautionary Information About Forward-Looking Statements

This Form 10-K 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 in Part I, “Item 1A. Risk Factors” and the following factors:

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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.

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 “Escalera Resources,” the “Company,” “we,” “our,” and “us” refer to Escalera Resources 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 Form 10-K.  Dollar amounts set forth herein are in thousands unless otherwise noted.

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PART I

ITEMS 1. AND 2. BUSINESS AND PROPERTIES

General and Overview

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 “ESCR” and our Series A Cumulative Preferred Stock is traded on that market under the symbol “ESCRP”. Our corporate offices are located at 1675 Broadway, Suite 2200, Denver, Colorado 80202, telephone number (303) 794-8445. Our website is www.escaleraresources.com. However the information contained on our website is not incorporated herein by reference and should not be considered a part of this Form 10-K.

Our current production primarily consists of natural gas from two core properties located in southern 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 2014 production volume was natural gas.

As of December 31, 2014, we had estimated proved reserves of 85.8 Bcf of natural gas and 247 MBbl of oil, for a total of 87.3 Bcfe. Of these estimated proved reserves, 57% were proved developed and 98% were natural gas.  As compared to our 2013 year-end reserve estimate, our 2014 year-end total proved reserve estimate increased by 12.6 Bcfe after reductions for 2014 production, which was a result of increases in both revisions of estimates, and current year extensions and discoveries.  We had positive revisions of 18.0 Bcfe due primarily to the increase in natural gas prices used in the reserve estimate, as calculated in accordance with the SEC pricing rules.  Pricing increased 24% to $4.36 per MMBtu for the year ended December 31, 2014 from $3.53 per MMBtu for the year ended December 31, 2013.  As a result of the higher pricing, certain of our undeveloped well locations in our operated Catalina Unit, which were excluded from our 2013 estimate, became economic and are included in our 2014 year-end reserves.  The increase from the Catalina Unit reserves was offset by downward revisions in the reserve estimate at the Pinedale Anticline properties.  The downward revision in the Pinedale Anticline reserves reflects a steeper estimated decline curve than previously estimated. Our 2014 net production totaled 8.2 Bcfe. 

Our proved natural gas and oil reserves at December 31, 2014 had a PV-10 value of approximately $99.9 million, an increase of 28% from December 31, 2013, 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 Pinedale Anticline 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 11).

Beginning in the second half of 2014, natural gas and oil commodity prices decreased substantially as compared to prices during the first half of 2014, and pricing has continued to decline through the first quarter of 2015.  Assuming that these prices do not recover during the remainder of 2015, we would expect significant negative revisions to our estimated proved natural gas and oil reserves based upon this low pricing environment. Any further decrease in the expected future natural gas prices could potentially result in impairment charges after we estimate the 2015 year-end discounted future net cash flows from our proved properties and compare them with their respective net book values. Further, the low natural gas and oil prices will affect the economic feasibility of developing our proved undeveloped reserves and will also likely limit the amount of capital resources we have at our disposal to develop our proved undeveloped reserves, including borrowing capacity, if any, that could be drawn on our existing credit facility. These circumstances may lead to the reclassification of our resources from proved undeveloped reserves to unproved, which could have material adverse implications for the value of our Company, cash flows, access to capital, liquidity and financial condition.

 

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Strategy

As a result of lower market prices for natural gas and our depleting asset base, our cash flow from operations has decreased over the past several years, while our level of indebtedness has increased.  As of December 31, 2014, we had $47,515 outstanding on our credit facility.  The borrowing base on our credit facility is redetermined on a semi-annual basis and given the recent declines in natural gas and oil commodity prices, it is likely that our borrowing base will be reduced effective May 2015. Given the decreases in our operating cash flows, due primarily to the recent declines in natural gas prices and the anticipated decrease in our borrowing base, we are focused on the following near-term business strategies:  1) identifying potential merger candidates which we believe offer improved opportunities to obtain capital to develop our natural gas and oil properties, to acquire natural gas properties and to cure any borrowing base deficiencies that result from our next borrowing base redetermination; 2) maintaining production while efficiently managing, and in some cases reducing, our operating and general and administrative (“G&A”) costs; and 3) evaluating asset divestiture opportunities which would allow us to reduce our indebtedness.  The Company has explored raising additional capital in order to pursue its objective of acquiring and developing natural gas properties, however, given our current capital structure and the recent declines in natural gas and oil commodity prices, raising such capital is unlikely. Our current capital structure is prohibitive for raising capital due primarily to certain terms and provisions of our Series A Preferred Stock. 

If we are able to raise additional capital with which to make acquisitions and fund the development of our properties, our objective is to increase long-term shareholder value by profitably growing our reserves, production, revenues, and cash flow. To meet this objective, we would primarily focus on:

During 2014, we invested $7.4 million in capital expenditures related to the exploration and development of our existing properties, as compared to $9.6 million in 2013.  Our 2014 capital spending program was primarily for non-operated drilling in the Spyglass Hill Unit, where the operator drilled and completed 23 new production wells.  Nine additional wells are in progress in this area.  We also participated in the completion of the final well located in the Mesa “B” participating area on the Pinedale Anticline.  

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). Due to the current market and commodity price conditions, we have not budgeted for any capital projects in 2015, and we will assess opportunities on an individual basis.  If economic conditions were to improve, we may drill and complete up to five producing wells and two injection wells (1.2 wells, net) located in the Catalina Unit during the second half of 2015.  The expected cost, net to our interest, for this program would be approximately $1.5 million. The proposed wells are located largely on another working interest owner’s leases.  If this owner does not consent to drilling, we would have to bear the full cost of the drilling program in order to complete the wells (approximately $6.5 million).  Our ability to execute the program is dependent on both the consent of the other working interest owner, as well as our cash resources.    

We also continue to evaluate acquisition 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 2015 capital expenditures. 

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Properties and Operations

As of December 31, 2014, we owned interests in over 1,200 producing wells and had an acreage position of 343,947 gross (112,219 net) acres, of which 268,820 gross (95,661 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 96% of our proved reserves as of December 31, 2014, and 94% of our 2014 production.

As of December 31, 2014, 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 approximately 134,800 gross (23,200 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 2014, we recognized net sales volumes from the coalbed natural gas projects in the Atlantic Rim of 6.3 Bcfe, which represented 77% of our total 2014 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 subject to our capital constraints discussed in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

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. 

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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, 2014.  Our Catalina wells are located in two separate PAs; PA “A” consists of 71 wells in which we have an 85.53% working interest and PA “B” consists of 12 wells in which we have a 100% working interest.  As the Catalina Unit PA expands, our working interest will continue to change. If the existing acreage is developed, we anticipate our working interest will be approximately 61%. 

Production in the Catalina Unit resulted in net sales volumes of 4.6 Bcf in 2014, which represented 55% of our total sales volumes for 2014. During 2014, our average daily net production at the Catalina Unit was 12,470 Mcf.

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.

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 have received a permit 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 operator 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, LLC

Through a wholly-owned subsidiary, Eastern Washakie Midstream, 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 less than 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 Resources, Inc. (“Warren”), growth from the 2013 and 2014 drilling program was limited.   It is unknown if future development from the Spyglass Hill Unit will result in production growth at 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 8.90%. 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, 2014, our working interest was 28.59% in the 113 producing 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, 2014 was 22.99% in 81 producing wells in

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this PA, 32 of which were drilled in 2014.  We also have ownership in a total of 6,282 gross (757 net) acres in the Grace Point PA. Our working interest as of December 31, 2014 was 12.04% in 26 producing wells.  During 2014, net production from the Spyglass Hill Unit totaled 1.8 Bcf, or an average daily net production of 4,839 Mcf per day, representing a decrease of 9% as compared to 2013. Due to infrastructure constraints, primarily related to the water injection capacity, we have not realized an increase in production from the 2014 and 2013 drilling programs. 

The federal exploratory agreement governing the Spyglass Hill Unit states that a minimum of 25 wells must be drilled by September of each year, or the unit will be terminated.  If the Spyglass Hill Unit were to terminate, any undeveloped federal lease acreage at that time would be extended for two years and if it remains undeveloped (at the end of the two year period), such leases in the unit will expire.  Any undeveloped acreage located on state or fee leases would immediately expire upon termination of the unit.  In January 2015, Warren announced that given the current economic conditions, it does not plan to drill additional wells in 2015.  To date, nine of the 25 wells have been drilled to satisfy the 2015 requirement.  Refer to discussion under Item IA. Risk Factors for additional information on the implications of unit contraction.

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 235 non-operated wells that represented 17% of our total production for 2014. Our net production from the Mesa Units in 2014 was 1.4 Bcfe, or 3,823 Mcfe per day, net to our interest. 

As of December 31, 2014, in the Mesa “A” PA, there were 59 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. The operator is currently drilling in this PA. 

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 140 producing wells that produced 1.2 Bcfe in 2014, net to our interest, a decrease of 28% as compared to 2013. 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. The final well was completed in the Mesa “B” PA during 2014.

In the Mesa “C” PA, where we have a working interest of 6.40%, 34 wells produced 232 MMcfe in 2014, net to our interest, a decrease of 14% as compared to 2013. We have 1,000 gross (65 net) acres in the Mesa “C” PA.  We expect the operator to shift its efforts to drilling and development of Mesa C” once Mesa “A” is fully drilled. 

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

Conventional Development Opportunity – Dakota, Frontier, and Niobrara

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.  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.  Our working interest in this well is 95% before payout. After payout, our working interest will decrease to 87%.

The Company received approval from the Wyoming Oil and Gas Commission to comingle gas production from the Frontier, Dakota, and Niobrara formations produced from the well in October 2014.  The Company is now awaiting approval from the BLM.  Upon approval, we may begin producing gas from the Dakota and Frontier formations as early as the third quarter of 2015. 

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Using the data provided by this well, we are currently evaluating the potential for conventional development in the Atlantic Rim area where we hold an interest in approximately 35,000 net acres.

Northeast Nevada

We have leased 22,493 gross (6,087 net) acres, in the Huntington Valley in Elko and White Pine Counties, Nevada. In 2014, Noble Energy formed the Desert Moon Unit, a federal exploratory unit to which roughly 4,500 net acres are committed.  The play has unconventional oil potential.  The operator began drilling a horizontal well in the unit 2014, but due to our limited capital availability, we declined participation in this well.  Depending on the results of the exploratory well and the availability of capital, we may participate in the drilling of future wells. 

Reserves

We engaged an independent petroleum engineering firm, Netherland, Sewell & Associates, Inc. (“NSAI”) to prepare our reserve estimates at December 31, 2014, 2013 and 2012. 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 Mr. David Miller and Mr. John Hattner. Mr. Miller, a Licensed Professional Engineer in the State of Texas (No. 96134), has been practicing consulting petroleum engineering at NSAI since 1997 and has over 15 years of prior industry experience. Mr. Hattner has been practicing consulting petroleum geology at NSAI since 1991. Mr. Hattner, a Licensed Professional Geoscientist in the State of Texas, Geology (No. 559), has been practicing consulting petroleum geoscience at NSAI since 1991 and has over 11 years of prior industry experience.  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 Messrs Miller and Hattner are proficient in applying industry standard practices to engineering and geosciences evaluations as well as applying SEC and other industry reserves definitions and guidelines.

Our Vice President of 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 Bachelor of Science degree in Petroleum Engineering from the Colorado School of Mines and has over 25 years of experience in petroleum engineering and oil and gas operations.  In addition, we have leveraged the technical expertise of an external consultant over the past five years with more than 30 years of resevoir engineering experience.  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 100% of our reserves 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 Form 10-K as Exhibit 99.1.

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

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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 37.6 Bcfe and 14.9 Bcfe for the years ended December 31, 2014 and 2013, respectively.  During the year ended December 31, 2014, we had positive revisions of approximately 23.4 Bcfe in proved undeveloped reserves primarily due to the increase in natural gas prices, which made development of these reserves, located in our Catalina Unit and the non-operated Doty Mountain PA, economic. During 2014, the Company invested approximately $1.9 million to convert 1.0 Bcfe proved undeveloped reserves into proved developed reserves.   The conversion of these undeveloped reserves into developed reserves was due to developmental drilling in the Doty Mountain PA in the Atlantic Rim. We have not recognized any reserves that have remained undeveloped for a period of five years or more. 

The table below shows the 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 14 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

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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, 2014, 2013 and 2012.

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Derivative Instruments

We have entered into various derivative instruments to mitigate the risk associated with downward fluctuations in the prices of natural gas and oil 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 of the various derivative instruments depends on senior management’s view of market conditions, available contract prices and our operating strategy.  In accordance with our current credit agreement, we have hedged at least 85% of our projected production through 2016 based on our third-party prepared reserve report at December 31, 2014.  

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Our outstanding derivative instruments as of December 31, 2014 are summarized below:

 

 

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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, 2014. 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, 2014. Certain acreage is included in both tables as we hold both a working interest and a royalty interest. Undeveloped acreage includes lease hold 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. The Company has not assigned any proved undeveloped reserves to leases scheduled to be drilled after lease expiration. 

Significant Developments since December 31, 2013 

During 2014,  we participated in drilling 32 new producing wells in the Spyglass Hill Unit, as well as the final well in the Mesa “B” PA.  

On March 24, 2014, we accepted subscription agreements for a private offering of our common stock.  The gross proceeds were $4,825, or $4,158 net of placement agent and legal fees.  The offering was effected through a private placement transaction with accredited investors. The proceeds have helped us meet our working capital needs and fund capital expenditures. 

On August 29, 2014, we replaced our existing credit facility with a $250 million credit facility with Societe Generale.  The new credit facility increased our borrowing base to $50 million and extended the maturity date to August 2017.   The new facility also has a more flexible covenant structure than our previous credit facility, which management believes to be essential as we look to expand and grow operations. 

Marketing and Major Customers 

The principal products we produce are natural gas and 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 and 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, 2014, 2013 and 2012, we sold 90%, 91% and 93%, respectively, of our total natural gas and oil production to Summit Energy, LLC. 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 are accessible to us.

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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.  We also perform a title investigation before acquiring undeveloped leasehold interests.

Our credit agreement is secured by a first lien on substantially all of our assets.  In addition, our properties are subject to 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.

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 may purchase some of their anticipated winter and summer months’ 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.

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 have encountered 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, natural gas and oil 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 natural gas and oil 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 natural gas and oil production below the rate that would otherwise exist in the absence of such laws, regulations and orders. The regulatory burden on the natural gas and oil industry increases our costs of doing business and consequently affects our profitability. See Item 1A. Risk Factors – Our operations are subject to governmental risks that may impact our operations

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

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 fluid under pressure into tight rock formations to stimulate hydrocarbon production. These formations are generally geologically separated and isolated from fresh ground water supplies by protective rock layers. The fracture stimulation fluid is typically comprised of over 99% water and sand, with the

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remaining constituents consisting of chemical additives designed to optimize the fracture stimulation treatment and production from the reservoir. 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 natural gas and oil 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, 2014, we had 27 employees. None of our employees are subject to a collective bargaining agreement.  We lease 7,470 square feet of office space in Denver, Colorado for our corporate office, 4,919 square feet of office space in Houston, Texas for our executive office and 966 square feet in Casper, Wyoming for our regional office.

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 (“Act”), as well as our proxy statement for our 2015 Annual Meeting of Shareholders filed under Section 14(a) of the Act, are available on our website at http://www.escaleraresources.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:

Escalera Resources Co.

Attn: 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.escaleraresources.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 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.

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.

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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.

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 a 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

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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.

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.

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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. Each of these risk factors, as well as other risks described elsewhere in this Form 10-K, 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 and the borrowing base available under our credit facility, and could impair our ability to grow or to satisfy fixed payment obligations on our indebtedness.

Natural gas comprised approximately 98% of our total production for the year ended December 31, 2014 and represented 98% of our total proved reserves as of December 31, 2014. Our revenues, profitability, liquidity, future rate of growth, the borrowing base under our credit facility 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 particularly influenced by significant changes in weather and 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 proved 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.

Availability under our bank credit facility depends on a borrowing base, which is subject to redetermination by our lenders.  If our borrowing base is reduced, we may be required to repay amounts outstanding under the credit facility. 

Our credit facility limits the amounts we can borrow based on the borrowing base amount, as determined by our lenders. Our lenders determine our borrowing base using several factors, which include the calculated value of our proved reserves using commodity pricing assumptions as determined by the lenders, with effect given to our derivative positions.  Our lenders can adjust the borrowing base and the borrowings permitted to be outstanding under the credit facility. Our credit facility provides for semi-annual borrowing based redeterminations on April 1 and October 1.  As a result of the lower commodity prices, it is likely that our borrowing base will be reduced at the next redetermination date.  Any downward adjustment of the borrowing base in excess of the then outstanding borrowings would require that we repay such difference. If we experience a reduction in our borrowing base as result of a redetermination, any required repayments would reduce our liquidity and would likely impact our ability to fund future capital spending, our ability to maintain our current facilities or our ability to make future dividend payments on our Series A Preferred Stock.  Any significant borrowing base reduction may require us to sell certain assets in order to meet the associated repayment requirements.     

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Our independent registered public accounting firm has indicated that our financial condition raises substantial doubt as to our ability to continue as a going concern.

Our financial statements have been prepared assuming that we will continue to operate as a going concern, which contemplates the realization of assets and the satisfaction of liabilities in the normal course of business. However, our independent registered public accounting firm has included in its audit opinion for the year ended December 31, 2014, a statement that there is substantial doubt as to our ability to continue as a going concern.  The inclusion of the going concern paragraph in the independent registered public accounting firm’s audit opinion triggers an event of default under our credit facility.  Although we are working to obtain a waiver from our lenders, it has not been received as of the date of this Form 10-K, and therefore our lenders could elect to declare all principal and interest outstanding to be due and payable.  We can provide no assurance that we will be able to obtain such waiver.  The reaction of investors to the inclusion of a going concern statement by our auditors, our current lack of cash resources and our potential inability to continue as a going concern may materially adversely affect our common and preferred share prices and our ability to obtain additional financing or new capital. 

If we are unable to comply with the restrictions and covenants in our credit facility, there could be a default under the terms of the credit agreement, which could result in an acceleration of payment of borrowings and would impact our ability to maintain our current operations, increase our reserves, and/ or pay dividends on our Series A Preferred Stock.

Under our credit facility, we are 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 4.0 to 1.0. Covenant restrictions may prevent us from taking actions that we believe would be in the best interest of our business, may require us to sell assets or take other actions to reduce indebtedness to meet our covenants, and may make it difficult for us to successfully execute our business strategy or effectively compete with companies that are not similarly restricted.

As a result of the current price environment and our depleting asset base, it is likely that we will be unable to meet the funded debt to EBITDAX ratio required in the credit agreement in future periods, including the first quarter of 2015.  We are working with our bank to obtain a waiver or to modify the covenant structure in our credit agreement. If we are not able to meet the covenant, or any other financial or non-financial covenants, and we are 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 payment of all principal and interest outstanding.  In the event that we become non-compliant with any financial or non-financial covenant under our credit facility, we cannot provide assurance that we will be granted waivers or amendments to our credit agreement if for any reason we are unable to comply with the agreement, or that we will be able to refinance our debt on terms acceptable to us, or at all.

Our existing capital structure may impede our ability to raise additional financial resources. 

Our ability to continue as a going concern is dependent on raising additional financial resources to meet our current cash needs, and ultimately, to acquire and develop our natural gas and oil properties.  Our existing capital structure includes 1,610,000 outstanding shares of our Series A Preferred Stock, which rank ahead of our common stock in terms of dividends, priority of payment and liquidation premiums.  As a result, it may be challenging for us to raise additional capital through the issuance of our common stock.  Among other things, we may need to propose amendments to certain key financial terms of the articles supplementary for our Series A Preferred Stock in order to improve our ability to raise additional capital to meet our current cash needs, and ultimately, to identify and complete acquisitions and to resume our development efforts. 

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Our significant indebtedness could adversely affect our business, results of operations, and financial condition.

As of December 31, 2014, we had $47,515 drawn under our bank credit facility, in addition to our outstanding Series A Preferred Stock, which requires payment of cumulative cash dividends at a rate of 9.25% per year on the outstanding stated amount of $37,972.

Our indebtedness affects our operations in several ways, including;

In addition, 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 our future financial 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.

Please see also the risk factor Common stockholders may be diluted due to the conversion of our preferred stock or future sale for additional risks associated with our Series A Preferred Stock.     

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

A significant amount of our business is conducted through operating agreements under which we own partial interests in oil and natural gas wells. If we do not operate the wells in which we own an interest, we do not have control over normal operating procedures, expenditures or future development of the 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 depends upon a number of factors outside of our control, including the operator’s:

Since we typically 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.

The federal exploratory agreement governing our Spyglass Hill Unit states that a minimum of 25 wells must be drilled by September of each year, or the unit will be terminated.  If the Spyglass Hill Unit were to terminate, any undeveloped federal lease acreage at that time would be extended for two years and if it remains undeveloped (at the end of the two year period), such leases in the unit will expire.  Any undeveloped acreage located on state or fee leases would immediately expire upon termination of the unit.  As a result, we would lose our opportunity to drill and produce new wells on any expired leases. It may also inhibit our ability to utilize gathering and transportation systems that are located

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outside the contracted PA.  The Unit operator, Warren Resources Co. (“Warren”), announced in January of 2015 that given the current economic conditions, it does not plan to drill additional wells in 2015.  To date, nine of the 25 wells have been drilled to satisfy the 2015 requirement.  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. At December 31, 2014, we had 5.3 Bcf of proved undeveloped located within the Spyglass Hill Unit; however, all of these reserves are located within the boundaries of the current PA. 

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 associated drilling, operating and other costs. Acquisition and completion decisions generally are based on subjective judgments and assumptions that are often speculative. We cannot predict with certainty the production potential of a particular property or well. Furthermore, the successful completion of a well does not ensure a profitable return on the investment. There are a variety of geological, operational, mechanical 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:

Our operations require substantial capital and we may be unable to obtain needed financing on satisfactory terms.

The oil and gas industry is capital intensive. We have spent, and will continue to need 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 have to drill additional water disposal wells to ensure we are in compliance with existing laws.

We are currently evaluating our water disposal process within certain acreage in the Catalina Unit to ensure we are in compliance with existing laws.  As a result of our evaluation, we may need to drill up to two additional water disposals

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wells during 2015 at an anticipated cost to us in the range of $1.5-$4 million.  Failure to comply with these laws may result in fines and other penalties.

Unless we replace our natural gas and oil reserves, our reserves and production will decline, which would adversely impact our business, financial condition and results of operations. 

Producing natural gas and oil reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. 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 be unable to develop our existing acreage due to the environmental and political pressures around natural resource development.

Our 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 public and private 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 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, or similar change, 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 of exploration and development of natural gas or oil resources, which could negatively affect our financial condition and results of operations.    

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.

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.

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We maintain insurance against some, but not all, of the risks described above. This 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 expose us to operational and financial risks.

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 strategy, and we may not be able to identify, acquire, or integrate acquisitions successfully.

In recent years there has been intense competition for acquisition opportunities in our industry, and this environment can be particularly challenging for a company of our size with our limited resources. Our ability to identify and complete acquisitions is dependent upon, among other things, our ability to obtain debt and equity financing, which is significantly constrained at present due to our existing debt levels, and, in some cases, regulatory approvals. Our ability to pursue an acquisition strategy will 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, 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.

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

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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 Form 10-K 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 Form 10-K should not be considered as the market value of our natural gas and oil 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 Form 10-K, 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 SEC rules require 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.

 

Beginning in the second half of 2014,  natural gas and oil commodity prices decreased substantially as compared to prices during the first half of 2014, and pricing has continued to decline through the first quarter of 2015.  Assuming that these prices do not recover during the remainder of 2015, we would expect significant negative revisions to our estimated proved natural gas and oil reserves based upon this low pricing environment. Such depressed natural gas prices, if experienced throughout the majority of 2015, could potentially result in impairment charges after we estimate the 2015 year-end discounted future net cash flows from our proved properties and compare them with their net book value. Further, the low natural gas and oil prices will affect the economic feasibility of developing our proved undeveloped reserves, and will also likely limit the amount of capital resources we have at our disposal to develop our proved undeveloped reserves, including borrowing capacity, if any, that could be drawn on our existing credit facility. These circumstances may lead to the reclassification of our resources from proved undeveloped reserves to unproved, which could have material adverse implications for the value of our company, cash flows, access to capital, liquidity and financial condition.

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, reduce our exposure to adverse fluctuations in the prices of natural gas and oil, and meet the requirements of our existing credit facility, 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.

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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 2014, we sold approximately 90% 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

Nasdaq has stock market listing standards for share prices and market capitalization, and failure to comply with the standards may result in the Company’s common stock being de-listed from Nasdaq.

On January 20, 2015, we received notice from the Nasdaq Listing Qualifications Department indicating that our common stock is subject to potential delisting from the Nasdaq because our common stock had closed below the minimum $1.00 per share requirement for 30 consecutive days.  We have been provided 180 calendar days, or until July 20, 2015, to regain this compliance.  If we fail to regain compliance before July 20, 2015, but meet all of the other applicable standards for initial listing on the Nasdaq Capital Market with the exception of the minimum bid price rule, then we may be eligible to have an additional 180 calendar days, or until January 17, 2016, to regain compliance. If our common stock is delisted from Nasdaq, the price of our common stock may decrease further and our ability to secure additional financing through the issuance and sale of equity could be adversely affected.  In addition, upon such delisting and if we were not able to list our common stock on another recognized stock exchange, our common stock would be considered a “penny stock.” Broker-dealers desiring to make transactions in penny stocks have to comply with the SEC’s penny stock rules. These requirements would also likely adversely affect the trading activity in the secondary market for our common stock.

In the event that we continue to not pay dividends on our Series A Preferred Stock, our common stockholders may be diluted due to potential future payment of preferred stock dividends in shares of our common stock.

We recently suspended the dividend payment on our Series A Preferred Stock for the quarter ended March 31, 2015.  In the event that we are not able to, or do not, pay this dividend for a total of six quarters (whether consecutive or non-consecutive), we may have to pay a portion, or all, of accumulated and unpaid dividends in shares of our common stock. The issuance of common shares necessary to satisfy accumulated and unpaid dividends on our Series A Preferred Stock will dilute the ownership of our then existing common shareholders.

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. Key factors, some of which are outside our control, include the following:

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.

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

Our amended articles of incorporation and Third Amended and Restated Bylaws contain provisions that may make a change of control of the Company difficult, even if it may be beneficial to our stockholders.  Such provisions include the authorization given to our Board of Directors to issue and set the terms of preferred stock and limitations on stockholders’ 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 contained in 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.

Risks Related to the Ownership of our Series A Preferred Stock. 

Our Series A Preferred Stock ranks junior to all of our indebtedness and other liabilities and is effectively junior to all indebtedness and other liabilities of our subsidiaries.

In the event of our bankruptcy, liquidation, dissolution or winding-up of our business, our assets available to pay obligations on the Series A Preferred Stock will be available only after all of our indebtedness and other liabilities have been paid. The rights of holders of our Series A Preferred Stock to participate in the distribution of our assets will rank junior to the prior claims of our current and future creditors and any future series or class of preferred stock we may issue that ranks senior to the Series A Preferred Stock. As of the date hereof, 1,610,000 shares of Series A Preferred Stock, having a liquidation value of $25 per share plus accumulated but unpaid dividends, are outstanding. If we are forced to liquidate our assets to pay our creditors, we may not have sufficient assets to pay amounts due on any or all of the Series A Preferred Stock then outstanding. We have incurred and may in the future incur substantial amounts of debt and other obligations that will rank senior to the Series A Preferred Stock. At March 31, 2015, we had $47,515 of indebtedness under our credit facility, ranking senior to the Series A Preferred Stock. Our credit facility prohibits payments of dividends on the Series A Preferred Stock if we fail to comply with certain financial covenants or, at certain times, if a default or event of default has occurred. Certain of our other existing or future debt instruments may restrict the authorization, payment or setting apart of dividends on the Series A Preferred Stock.

 

Future offerings of debt or senior equity securities may adversely affect the market price of the Series A Preferred Stock. If we decide to issue debt or senior equity securities in the future, it is possible that these securities will be governed by an indenture or other instruments containing covenants restricting our operating flexibility. Additionally, any convertible or exchangeable securities that we issue in the future may have rights, preferences and privileges more favorable than those of the Series A Preferred Stock and may result in dilution to owners of the Series A Preferred Stock. We and, indirectly, our stockholders, will bear the cost of issuing and servicing such securities. Because our decision to issue debt or equity securities in any future offering will depend on market conditions and other factors beyond our control, we cannot predict or estimate the amount, timing or nature of our future offerings. The holders of the Series A Preferred Stock will bear the risk of our future offerings, reducing the market price of the Series A Preferred Stock and diluting the value of their holdings in us.

We may not be able to pay dividends in cash on the Series A Preferred Stock.

We suspended payment of dividends on the Series A Preferred Stock for the quarter ended March 31, 2015. We may not have sufficient cash to pay dividends on the Series A Preferred Stock in the future. Our ability to pay dividends may be impaired if any of the risks described in this Form 10-K, were to occur. In addition, payment of our dividends depends upon our financial condition and other factors as our Board of Directors may deem relevant from time to time. We cannot make assurances that our business will generate sufficient cash flow from operations or that future borrowings will be available to us in an amount sufficient to enable us to make distributions on our Series A Preferred Stock, or to pay our indebtedness or to fund our other liquidity needs.

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The Series A Preferred Stock has not been rated.

We have not sought to obtain a rating for the Series A Preferred Stock. No assurance can be given, however, that one or more rating agencies might not independently determine to issue such a rating or that such a rating, if issued, would not adversely affect the market price of the Series A Preferred Stock. In addition, we may elect in the future to obtain a rating for the Series A Preferred Stock, which could adversely affect the market price of the Series A Preferred Stock. Ratings only reflect the views of the rating agency or agencies issuing the ratings, and such ratings could be revised downward, placed on a watch list or withdrawn entirely at the discretion of the issuing rating agency if, in its judgment, circumstances so warrant. Any such downward revision, placing on a watch list, or withdrawal of a rating could have an adverse effect on the market price of the Series A Preferred Stock.

Certain provisions governing our Series A Preferred Stock may preclude us from taking important actions. 

Following a change of ownership or control other than a change of ownership or control (a) involving a Qualifying Public Company, see below, or (b) that is a Qualifying Event, see below, within 90 days following the date on which such change of ownership or control has occurred, we or the acquiring entity in such change of ownership or control must redeem the Series A Preferred Shares, in whole and not in part, for cash at $25 per share. Whether the amounts to effect such redemption would be available is not determinable at the present time. This obligation could also be a detriment to a possible merger or other business combination.

 

Following a change of ownership or control (a) involving a Qualifying Public Company or (b) that is a Qualifying Event, for a period of 90 days following the date on which the change of ownership or control has occurred, such Qualifying Public Company or the Company if there is a Qualifying Event will have the right, but not the obligation, to redeem the Series A Preferred Shares, in whole but not in party, for cash at $25 per share. Whether the amounts to effect such redemption would be available is not determinable at the present time. The existence of the Series A Preferred Stock could also be a detriment to a possible merger or other business combination.

 

“Qualifying Public Company” means a company with voting stock that is subject to a National Market Listing and that, on a pro-forma combined basis with the Company, had an EBITDA(X)-to-interest expense plus preferred dividends ratio of at least 2.0-to-1.0 for the 12-month period ending as of the end of that company’s fiscal quarter immediately preceding the subject change of ownership or control.

 

“Qualifying Event” means a change of ownership or control where, after the transaction, the Company has voting stock subject to a National Market Listing and, on a pro-forma combined basis, had an EBITDA(X)-to-interest expense plus preferred dividends ratio of at least 2.0-to-1.0 for the 12-month period ending as of the end of the Company’s fiscal quarter immediately preceding the subject change of ownership or control.

The market price of the Series A Preferred Stock could be substantially affected by various factors.

The market price of the Series A Preferred Stock will depend on many factors, which may change from time to time, including:

 

 

 

 

 

 

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As a result of these and other factors, investors who purchase the Series A Preferred Stock may experience a decrease, which could be substantial and rapid, in the market price of the Series A Preferred Stock, including decreases unrelated to our operating performance or prospects.

We may issue additional shares of Series A Preferred Stock and additional series of preferred stock that rank on parity with the Series A Preferred Stock as to dividend rights, rights upon liquidation, or voting rights.

We are allowed to issue additional shares of Series A Preferred Stock and additional series of preferred stock that would rank equally to the Series A Preferred Stock as to dividend payments and rights upon our liquidation, dissolution or winding up of our affairs pursuant to our restated articles of incorporation, as amended, and the certificate of determination for the Series A Preferred Stock without any vote of the holders of the Series A Preferred Stock. The issuance of additional shares of Series A Preferred Stock and preferred stock that would rank on parity with the Series A Preferred Stock could have the effect of reducing the amounts available to the current holders of our Series A Preferred Stock upon our liquidation or dissolution or the winding up of our affairs. It also may reduce dividend payments to the current holders of the Series A Preferred Stock if we do not have sufficient funds to pay dividends on all Series A Preferred Stock outstanding and other classes of stock with equal priority with respect to dividends.

 

In addition, although holders of Series A Preferred Stock are entitled to limited voting rights with respect to such matters, the Series A Preferred Stock will vote separately as a class along with the holders of all other classes or series of our equity securities we may issue upon which similar voting rights have been conferred and are exercisable and which are entitled to vote as a class with the Series A Preferred Stock. As a result, the voting rights of holders of Series A Preferred Stock may be significantly diluted, and the holders of such other series of preferred stock that we may issue may be able to control or significantly influence the outcome of any vote.

 

Future issuances and sales of preferred stock ranking on parity with the Series A Preferred Stock, or the perception that such issuances and sales could occur, may cause prevailing market prices for the Series A Preferred Stock and our common stock to decline and may adversely affect our ability to raise additional capital in the financial markets at times and prices favorable to us.

Holders of Series A Preferred Stock have limited voting rights.

Voting rights as a holder of Series A Preferred Stock are limited. Our shares of common stock are the only class of our securities that carry full voting rights. Voting rights for holders of Series A Preferred Stock exist primarily with respect to the ability to elect two additional directors to our Board of Directors (voting together with the holders of any other classes of securities we may issue with similar voting rights), subject to certain limitations, in the event we do not pay dividends on the Series A Preferred Stock for a total of six consecutive or non-consecutive quarterly period or upon a “Listing Event”, which  means, with respect to the Series A Preferred Stock, if it is not listed on certain specified national stock exchanges (including the Nasdaq) for 180 or more consecutive days. As indicated above, we have received a notice from the Nasdaq Listing Qualifications Department that our common stock is subject to potential delisting from the Nasdaq because the closing bid price of our common stock had closed below the minimum $1.00 per share requirement for 30 consecutive days. We have been provided until July 20, 2015, to regain compliance and may be able to obtain an additional 180 calendar days (until January 7, 2016) under certain circumstances to regain compliance, which cannot be assured. Thus, absent such

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compliance or redemption in full of the Series A Preferred Stock, we may be required to create two additional board seats to our Board of Directors to be filled by a vote of the holders of the Series A Preferred Stock.

 

In addition, holders of the Series A Preferred Stock have the right as a class to vote on amendments to provisions of our restated articles of incorporation or the certificate of determination relating to the Series A Preferred Stock that would:

 

 

 

 

provided, however, that no vote will be required in connection with the change of ownership or control if a contemporaneous deposit is made for redemption in cash for all of the Series A Preferred Stock.  Other than the limited circumstances described above, holders of Series A Preferred Stock do not have any voting rights.

Holders of a majority of our outstanding Series A Preferred Stock can agree to amend the rights and preferences of the Series A Preferred Stock by a vote which could be to the detriment of minority holders of the Series A Preferred Stock.

As indicated in the risk factor immediately above, the holders of our Series A Preferred Stock have certain limited voting rights, one of which allows a majority of the holders of Series A Preferred Stock to agree to amendments to our restated articles of incorporation or our certificate of determination relating to the Series A Preferred Stock that could materially and adversely affect the rights of the holders of the Series A Preferred Stock. There may be instances where the interests of the holders of a majority of the Series A Preferred Stock in taking such action is prejudicial to, and is not aligned with, the interests of other Series A Preferred shareholders. Accordingly, holders of a minority of such shares would not be able to block amendments that could materially and adversely affect them, for example, amendments to redeem the Series A Preferred Stock at a lower price than the liquidation amount or amendments to decrease the dividend rate.

The Series A Preferred Stock has only a limited trading market, which may negatively affect its value and the ability to transfer and sell shares.

The Series A Preferred Stock has only a limited trading market. The volume of trades of shares of the Series A Preferred Stock on the Nasdaq is often low, and an active trading market on the Nasdaq for the Series A Preferred Stock may not be maintained in the future and may not provide adequate liquidity. The liquidity of any market for the Series A Preferred Stock that may exist now or in the future will depend on a number of factors, including prevailing interest rates, the dividend rate on our common stock, whether we pay dividends in cash, our financial condition and operating results, the number of holders of the Series A Preferred Stock, the market for similar securities and the interest of securities dealers in making a market in the Series A Preferred Stock. As a result, the ability to transfer or sell the Series A Preferred Stock could be adversely affected.

 

If the Series A Preferred Stock or our common stock is delisted, the ability to transfer or sell shares of the Series A Preferred Stock may be limited, and the market value of the Series A Preferred Stock will likely be materially adversely affected.

 

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Other than in connection with a change of control, the Series A Preferred Stock does not contain provisions that are intended to protect stockholders if our common stock is delisted from the Nasdaq. Since the Series A Preferred Stock has no stated maturity date, stockholders may be forced to hold their shares of the Series A Preferred Stock and receive stated dividends on the Series A Preferred Stock when, and if authorized by our board of directors and paid by us with no assurance as to ever receiving the liquidation value thereof. In addition, if our common stock is delisted from the Nasdaq, it is likely that the Series A Preferred Stock will be delisted from the Nasdaq as well. Accordingly, if the Series A Preferred Stock or our common stock is delisted from the Nasdaq, the ability to transfer or sell shares of the Series A Preferred Stock may be limited and the market value of the Series A Preferred Stock will likely be materially adversely affected.

 

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

 

ITEM 3. LEGAL PROCEEDINGS 

From time to time, we are involved in various legal proceedings, including the matter below.  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.

On January 29, 2015, two former employees each filed claims against the Company, which generally assert breach of contract in connection with their termination from the Company.  We do not believe the cases have merit, and is defending the cases vigorously.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

 

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PART II

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

Common Stock

Market Information. Our common stock is currently traded on the NASDAQ Global Select Market under the symbol “ESCR”. The range of high and low sales prices for our common stock for each quarterly period from January 1, 2013 through December 31, 2014 as reported by the NASDAQ Stock Market, is set forth below:

On April 2, 2015, the closing sales price for the common stock as reported by the NASDAQ Global Select Market was $0.34 per share. 

Holders. On April 2, 2015, the number of holders of record of our common stock was 851. 

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, if any, for the future operation and development of our business including exploration, development and acquisition activities. Our credit agreement requires our lenders’ consent to the payment of dividends on our common stock and any stock redemptions we might wish to make. Any future dividends would also 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. 

 

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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 are 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 current production primarily consists of natural gas from two core properties located in southwest 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 2014 production volume was natural gas.

As of December 31, 2014, we had estimated proved reserves of 85.8 Bcf of natural gas and 247 MBbl of oil, or a total of 87.3 Bcfe. Of these estimated proved reserves, 57% were proved developed and 98% were natural gas. As compared to our 2013 year-end reserve estimate, our 2014 year-end total proved reserve estimate increased by 12.6 Bcfe after reductions for 2014 production, which was a result of increases in both extensions and discoveries, and revision of estimates.  We had positive revisions of 18.0 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”) rules.  Pricing increased 24% from $3.53 per MMBtu for the year ended December 31, 2013, to $4.36 per MMBtu for the year ended December 31, 2014.  As a result of the higher pricing, certain of our undeveloped well locations in our Catalina Unit, which were excluded from our 2013 estimate, became economic, as of December 31, 2014. The increase from the Catalina Unit reserves was offset in part by downward revisions in the reserve estimate at the Pinedale Anticline properties.  The downward revision in the Pinedale Anticline reserves is a reflection of the lower production volumes from these properties in 2014 due to steeper estimated declines in production than previously estimated. Our 2014 net production totaled 8.2 Bcfe.

Our proved oil and gas reserves at December 31, 2014 had a PV-10 value of approximately $99.9 million, an increase of 28% from December 31, 2013, 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 Pinedale Anticline 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 11).

Beginning in the second half of 2014, natural gas and oil commodity prices decreased substantially as compared to prices during the first half of 2014, and pricing has continued to decline through the first quarter of 2015.  Assuming that these prices do not recover during the remainder of 2015, we would expect significant negative revisions to our estimated proved natural gas and oil reserves based upon this low pricing environment. Any further decrease in the expected future natural gas prices could potentially result in impairment charges after we estimate the 2015 year-end discounted future net cash flows from our proved properties and compare them with their respective net book values. Further, the low natural gas and oil prices will affect the economic feasibility of developing our proved undeveloped reserves and will also likely limit the amount of capital resources we have at our disposal to develop our proved undeveloped reserves, including borrowing capacity, if any, that could be drawn on our existing credit facility. These circumstances may lead to

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the reclassification of our resources from proved undeveloped reserves to unproved, which could have material adverse implications for the value of our Company, cash flows, access to capital, liquidity and financial condition.

Business strategies

As a result of lower market prices for natural gas and our depleting asset base, our cash flow from operations has decreased over the past several years, while our level of indebtedness has increased.  As of December 31, 2014, we had $47,515 outstanding on our credit facility.  The borrowing base on our credit facility is redetermined on a semi-annual basis and given the recent declines in natural gas and oil commodity prices, it is likely that our borrowing base will be reduced effective May 2015. Given the decreases in our operating cash flows, due primarily to the recent declines in natural gas prices and the anticipated decrease in our borrowing base, we are focused on the following near-term business strategies:  1) identifying potential merger candidates which we believe offer improved opportunities to obtain capital to develop our natural gas and oil properties, acquire natural gas properties and to cure any borrowing base deficiencies that result from our next borrowing base redetermination; 2) maintaining production while efficiently managing, and in some cases reducing, our operating and general and administrative (“G&A”) costs; and 3) evaluating asset divestiture opportunities which would allow us to reduce our indebtedness.  The Company has explored raising additional capital in order to pursue its objective of acquiring and developing natural gas properties, however, given our current capital structure and the recent declines in natural gas and oil commodity prices, raising such capital is unlikely. Our current capital structure is prohibitive for raising capital due primarily to certain terms and provisions of our Series A Preferred Stock. 

If we are able to raise additional capital with which to make acquisitions and fund the development of our properties, our long-term objective is to increase shareholder value by profitably growing our reserves, production, revenues, and cash flow. We believe we can accomplish this through: (i) selectively pursuing acquisitions of abundant, low cost natural gas assets that are currently undervalued or underutilized; (ii) identifying alternative ways to enhance the value of our natural gas reserves (iii) 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 above average returns.

Developments since December 31, 2013

During 2014, we invested $7,407 to continue to grow production and reserves in our core properties, including:

On March 24, 2014, we completed a private offering of our common stock to accredited investors.  The gross proceeds were $4,825, or $4,158 net of placement agent and legal fees.   We used the net proceeds of the offering to fund working capital needs, capital expenditures and for general corporate purposes.

On August 29, 2014, we replaced our previous credit facility with a $250,000 credit facility.  The new credit facility increased our borrowing base to $50,000 and extended the maturity date to August 2017.   

In May 2014, we entered into a letter agreement (“Letter Agreement”) to jointly initiate the development, construction and operations of a gas-to-liquids ("GTL") plant to be located in Wyoming.  Under the terms of the Letter Agreement,  we advanced $1,160 through December 31, 2014 on behalf of Wyoming GTL, LLC and its affiliate  (collectively, "WYGTL") to partially fund the feasibility studies and completion of the initial engineering and development plans for the GTL plant.  We advanced an additional $202 on behalf of WYGTL in January 2015.  In return, WYGTL assigned all development and engineering plans, contracts, rights, and technical relationships, among other rights (collectively, the "Rights"), to the Company. 

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The Letter Agreement expired effective January 29, 2015 as we were unable to agree on terms for a definitive agreement with WYGTL, as contemplated by the Letter Agreement.  In accordance with the provisions of the Letter Agreement, we requested WYGTL to repay to us, the total amount advanced, or $1,362.  We had not received the repayment as of the date of this Form 10-K and have filed a lawsuit against WYGTL for breach of the Letter Agreement terms, seeking recovery of the total amount advanced under the Letter Agreement.  

Challenges and opportunities

In addition to the impact of lower natural gas prices on our cash flow and the uncertainty in the future results of the redetermination of our borrowing base as noted above, 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. If average natural gas prices decline further or remain at low levels, it would likely reduce the value of our reserves, and consequently the borrowing base of our credit facility. Generating reserve and production growth while containing costs, is an ongoing focus for management, and is of particular importance in our business due to ongoing production and the reserve declines associated with oil and gas properties. Normally, we would seek to curtail these declines by drilling to find additional reserves, making acquisitions of additional reserves and exploiting new exploration opportunities.  However, at present, in order to execute on our business strategy, we will need to raise additional funds to support the future development of our properties. As discussed below in the Liquidity and Capital Resources section, our ability to obtain additional financial resources may be difficult due to our existing capital structure. 

Our ability to add reserves through drilling 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.  We are in the process of permitting wells proposed for drilling in the Catalina Unit, in the event that economic conditions and our financial position improve.  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 2015

Due to the current economic conditions, we have not budgeted for any capital projects in 2015, and we will assess opportunities on an individual basis.  If natural gas prices improve significantly, we may drill and complete up to five production wells and two injection wells (1.2 wells, net) located in the Catalina Unit during the second half of 2015.  The expected cost, net to our interest, for this program would be approximately $1.5 million. The proposed wells are located largely on another working interest owner’s leases.  If this owner does not consent to drilling, we would have to bear the full cost of the drilling program in order to complete the wells (approximately $6.5 million).  Our ability to execute the program is dependent on both the consent of the other working interest owner, as well as our cash resources.  There are currently no proposed drilling projects for the Spyglass Hill Unit for 2015. 

 

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RESULTS OF OPERATIONS

The table below provides a year-to-year overview of selected reserve, production and financial information. The information 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, 2014 compared to the year ended December 31, 2013

The following analysis provides comparison of the years ended December 31, 2014 and 2013.

Oil and gas sales, production volume and price comparisons

Oil and gas sales increased 7% to $34,136, primarily due to a 17% increase in the Colorado Interstate Gas (“CIG”) index, which is the index on which most of our natural gas volumes are sold, offset in part by an 11% decrease in production volumes, which is discussed in more detail below. 

As shown in the table above, our average realized gas price decreased 4% to $3.76 per Mcf.  In 2014, we realized natural gas prices lower than the prevailing market prices due to the net realized losses associated with the derivatives we had in place. 

Our total net production decreased 11% to 8.2 Bcfe, primarily due to lower production volumes from the Atlantic Rim and Pinedale Anticline properties.

Our total average daily net production at the Atlantic Rim decreased 8% to 17,308 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 23% to 3,823 Mcfe as a result of normal production declines, which are no longer offset by initial production of new wells. The initial production rates from wells in this field are very strong and then decline quickly. The operator drilled the final well in this field in early 2014, and therefore, we expect to see significant decreases, as there is no new production to offset this decline.  The operator has shifted its efforts to drilling and development of Mesa “A” PA and once fully drilled, the operator is expected to move onto the Mesa “C” PA. The drilling in the Mesa “A” PA is not expected to have a material impact on our production, as we have a small overriding royalty interest in the Mesa “A” 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 5% to $3,540 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 future development of the Catalina Unit and additional third party gas from other non-operated properties in the Atlantic Rim proximity.

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Price risk management

We recorded a net gain on our derivative contracts of $6,243. The net gain consisted of an unrealized non-cash gain of $6,478, which represents the change in the fair value of our commodity derivatives at December 31, 2014 based on the expected future prices of the related commodities, and a net realized loss of ($235) related to the cash settlement of certain of our derivative contracts.  The net realized loss included a realized gain of $1,343 upon the closure of commodity derivatives with the Company’s former lender.  

The fair value of derivative instruments we hold will continue to change until the contracts are settled, and in accordance with our credit facility, 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.

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

Well production costs increased 1% to $13,228, whereas production costs in dollars per Mcfe increased 13%, or $0.18 to $1.61 per Mcfe. The increase in total production costs was primarily due to a $234 increase in production costs at the Catalina Unit.  During the first quarter in 2013, we had deferred certain well maintenance activities to focus on an exploratory project, whereas in 2014, maintenance was at a more historically consistent rate.  In addition, we had higher production costs at the Catalina Unit as a result of an equipment outage due to a lightning strike in the third quarter of 2014.  This was offset, in part, by lower transportation charges at our Pinedale Anticline properties due to the decrease in production volumes.  Production costs on a per Mcfe basis were higher due to the overall decrease in production volumes, as a portion of our production costs are fixed or partially fixed.

Production taxes increased 3% to $4,028, and production taxes, on a dollars per Mcfe basis, increased 17%, or $0.07 to $0.49 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”) decreased 7% to $19,419, and depletion and amortization related to producing assets decreased 7% to $19,063. Expressed in dollars per Mcfe, depletion and amortization related to producing assets increased 4% to $2.32.  Our depletion rate was lower in 2014 for the Catalina Unit, due to an increase in our reserves and decrease in production, which were estimated to be higher in our year-end reserve report, primarily due to the increase 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, 2014, we recorded impairment and abandonment expense of $1,708, of which $758 was due to the write-off of a non-operated property in the Atlantic Rim.  Production from these wells has been limited, and the operator has indicated that it intends to plug and abandon wells in this area.  In addition, we wrote-off $950 of non-producing leases in Nebraska and Wyoming, which expire in 2015, as there is no plan to develop this acreage. 

Pipeline operating costs

Pipeline operating costs decreased 17% to $4,331, primarily due to lower power charges. Power charges were lower in 2014 due to $239 refund of certain exempt sales taxes. 

General and administrative

G&A expenses increased 31% to $7,094,  largely due to severance related expenses of $1,178 payable to three former employees of the company, including our former chief executive officer.  Approximately $525 of the severance expense

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is payable in 2016.  We also experienced an increase in legal expenses of $213 and additional Board of Directors related expenses of $127. 

Provision for gas-to-liquids advance

In 2014, we recorded a provision of $1,160 for the reimbursement of amounts advanced for the GTL plant by us through December 31, 2014.  In May 2014, we entered into a Letter Agreement to jointly initiate the development, construction and operations of a GTL plant to be located in Wyoming.  The Letter Agreement expired effective January 29, 2015 as we were unable to agree on terms for a definitive agreement with WYGTL, as contemplated by the Letter Agreement.  In accordance with the provisions of the Letter Agreement we requested WYGTL to repay to us the total amount we advanced, or $1,362.  We had not received the repayment as of the date of this Form 10-K and have filed a lawsuit against WYGTL for breach of the Letter Agreement terms, seeking recovery of the total amount advanced under the Letter Agreement.  As the future collection of this amount is uncertain, we recorded a provision to fully allow for the outstanding advances as of December 31, 2014. 

Deferred income taxes

During the year ended December 31, 2014, we recorded a deferred income tax benefit of $1,236. Our deferred income tax benefit reflects an effective book rate of 14.02% in 2014, which is lower than the 2013 rate due to the valuation allowance we recorded against our deferred tax assets in 2014, as it is uncertain as to whether we will realize the future benefit.  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 $70.6 million at December 31, 2014. Our current NOLs do not begin to expire for eight years.

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 CIG market price, 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.

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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

Transportation and gathering revenue decreased 25% to $3,745 due to the decrease in production volumes at the Catalina Unit discussed above.

Price risk management 

We recorded a net loss on our derivative contracts not designated as cash flow hedges of $(730) as a result of our hedging program used to mitigate our exposure to fluctuations in natural gas prices.  The net loss consisted of a realized gain of $6,185 related to the cash settlement of certain derivative contracts, and an unrealized non-cash loss of $(6,915), which represented the change in the fair value on our derivative instruments at December 31, 2013. 

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 expect to plug and abandon this well in 2015.   

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 was 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 the 2013 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

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. We 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

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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

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 the 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.

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. The content below addresses important factors affecting our financial condition, liquidity and debt covenant compliance.

Credit Facility 

We currently have a $250,000 revolving line of credit facility (the “Credit Facility”) in place with a $50,000 borrowing base.  At December 31, 2014, we had $47,515 outstanding on the Credit Facility. The Credit Facility is collateralized by our oil and gas producing properties and other assets. We have depended on our credit facilities 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 an exploration well in the Atlantic Rim. 

Borrowings under the Credit Facility bear interest at a daily rate based on our interest rate election of either the Base Rate or the LIBOR Rate.  Under the Base Rate option, interest is calculated at an annual rate equal to the highest of (a) the base rate for Dollar loans for such day, the Federal Funds rate for such day, or the LIBOR for such day plus (b) a margin ranging between 0.75% and 1.75% (annualized) depending on the level of funds borrowed. Under the LIBOR Rate option, interest is calculated at an annual rate equal to LIBOR, plus a margin ranging between 1.75% and 2.75% (annualized) depending on the level of funds borrowed.  The average interest rate on the facility at December 31, 2014, was 3.1%.

We are subject to a variety of financial and non-financial covenants under the Credit Facility.  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 4.0 to 1.0. 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

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foreclose on our assets. As of December 31, 2014, we were in compliance with all covenants under the facility, except as described in the following paragraph. 

 

Our independent registered public accounting firm has included in its audit opinion for the year ended December 31, 2014, a statement that there is substantial doubt as to our ability to continue as a going concern.  The inclusion of the going concern explanatory paragraph by our independent registered public accounting firm triggers an event of default under our credit facility.  We are working with our lenders to obtain a waiver for this condition.  Unless a waiver is obtained, the lender could elect to declare all principal and interest outstanding to be due and payable.  As a result, the outstanding balance on our credit facility is shown as a current liability on the consolidated balance sheet for the year ended December 31, 2014. 

As of December 31, 2014, our funded debt to EBITDAX ratio was 3.9 to 1.0.  We expect that for the quarter ended March 31, 2015, we will breach the required funded debt to EBITDAX ratio of 4.0:1.0.  We are also currently negotiating a waiver or amendment to our credit facility to modify the covenant structure. 

We are subject to a semi-annual borrowing based redetermination; the next of which is expected to be completed in May of 2015. Although we experienced reserve growth in 2014 as compared to 2013, the redetermination is based on our proved reserves, using price assumptions determined by our lenders, with consideration given to our derivative positions.  As a result of the recent decline in natural gas prices, we expect our borrowing base will be reduced.  The magnitude of this reduction is uncertain.  If, as a result of the redetermination, our borrowing base is reduced, we may be required to repay any amounts outstanding in excess of the newly-determined borrowing base immediately, or in monthly installments of a six-month period.  A decrease in our borrowing base will likely impact our ability to execute our 2015 capital expenditures and/or fund dividend payments on our Series A Preferred Stock (which payments were suspended in March 2015), or if significant, fund our operations. We will likely need to find other sources of capital, if available, to fund any such borrowing base reduction or to fund future capital expenditure and operating cash requirements. In the event that any such borrowing base reduction cannot be fully funded by cash on hand and cash flow generated from operations, our ability to fund such deficiency would be uncertain.

Other

In early 2014, we completed a private offering of our common stock to accredited investors, raising proceeds of $4,825, or $4,158 net of placement agent and legal fees. We used the net proceeds of the offering to fund working capital needs, capital expenditures, advances of funds for the GTL project, and for general corporate purposes.

We currently have an effective Form S-3 shelf registration statement on file with the SEC, which contemplates up to $200,000 of securities available for issuance, and could provide us the ability to raise additional funds through registered offerings of equity, debt or other securities.  However, in March 2015, we suspended the quarterly dividend payment on our Series A Preferred Stock, and as a result we are unable to issue common stock under our Form S-3 shelf registration statement until the fiscal year after our dividend payments are made current.  Depending on the type of offering, amounts raised utilizing our S-3 may be limited to a percentage of the amount of our common equity held by non-affiliates. 

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, we are also 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 natural gas and oil properties, or unsecured.  

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Capital Expenditures

Our primary capital expenditures by type for the years ended December 31, 2014 and 2013 were:

Year Ended December 31, 2014

Over the past two years we have limited our capital investment to stay within operating cash flow.  Our investment in 2014 was primarily focused on our properties in the Atlantic Rim, where we invested a total of approximately $6,456.  We participated in 32 new production wells in the Spyglass Hill Unit, nine of which were still in progress as of December 31, 2014, for a cost of $5,670, net to our interest.  We also invested $668 to replace certain compressor equipment at the Catalina Unit, which we expect to result in lower future operating costs. 

On the Pinedale Anticline, we invested  $492, net to our interest, primarily for the drilling and completion of the final well in the Mesa “B” PA. 

Year Ended December 31, 2013

In 2013 we spent $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.  

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 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. 

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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.

Working capital

Our working capital as of December 31, 2014, includes the impact of our debt reclassification to a current liability, due to the inclusion of a going concern explanatory paragraph in our audit opinion.  Excluding the impact of this reclassification, our working capital was higher as of December 31, 2014 as a result of a $3,344 increase in the fair value of our commodity derivatives as compared to December 31, 2013. 

Net cash provided by operating activities

Operating activities provided cash of $8,712 in 2014, as compared to $13,082 in 2013 and $19,468 for 2012. The primary source of cash during 2014 was a net loss of $(7,585), which was net of non-cash charges of $19,673 related to DD&A and accretion expense, $1,708 of impairment expense, and an increase in accounts payable and accrued expenses.  This was offset by a $6,790 unrealized gain related to the change in fair value of our derivative contracts, and a tax benefit of $1,236 for deferred income taxes. 

Our cash flow from operations for the year ended December 31, 2014 was lower, largely due to a decrease in production volumes of 11%, or 1.0 Bcfe   Additionally, our realized price decrease by approximately $0.17 per Mcfe. 

Net cash used in investing activities

Net cash used in investing activities was $(5,085) for 2014, as compared to $(10,523) in 2013 and $(25,773) in 2012. Our capital expenditures in 2014 were primarily related to participation in drilling and completion costs related to the Doty Mountain PA in the Spyglass Hill Unit, in which 32 wells were completed, and drilling and completion costs related to one new well on the Pinedale Anticline.         

In 2013, our capital costs 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

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new wells in 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.

Net cash used in financing activities

Our financing activities used cash of $(493) in 2014, as compared to cash provided by financing activities of $(3,830) and $1,697 in 2013 and 2012, respectively.  The cash used in financing activities in 2014 primarily related to the payment of dividends related to the Series A Preferred Stock, totaling $3,723.  We replaced our previous credit facility with a new credit agreement in August 2014 and as a result we paid financing costs of $949 in connection with our new credit facility.  This was offset by a private offering of our common stock for net proceeds of $4,158.  The cash used in financing activities in 2013 primarily related to the payment of dividends related to the Series A Preferred Stock, totaling $3,723.  We drew down $5,450 on the Credit Facility in 2012, primarily to finance our purchase of additional working interest in the Atlantic Rim, offset by the payment of dividends related to the Series A Preferred Stock, totaling $3,723.

Contractual Obligations

The following table summarizes our contractual obligations as of December 31, 2014:

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The Company also has employment agreements in place with certain executive officers that, among other things, specify severance payments an executive officer would receive upon termination or a change in control of the Company.  During 2014, we incurred severance costs of $1,178 related to such agreements.

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.

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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.

Our outstanding derivative instruments as of December 31, 2014 are summarized below:

 

 

 

 

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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, 2014.

Other Volumes Contracted

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

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GOING CONCERN

The Company's financial statements for the year ended December 31, 2014, have been prepared on a going concern basis, which contemplates the realization of assets and the settlement of liabilities and commitments in the normal course of business.  Our independent public accounting firm has issued its audit opinion with a statement that there is substantial doubt as to our ability to continue as a going concern as a result of the recent drop in natural gas and oil commodity prices, the potential impact to our borrowing base under our credit facility and our recurring losses over the past three years. The Company's ability to continue as a going concern is dependent on our ability to raise additional capital.  The financial statements do not include any adjustments relating to the recoverability and classification of assets or the amounts and classification of liabilities that might be necessary should we be unable to continue as a going concern.

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.

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, 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.

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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 2014, Netherland, Sewell & Associates, Inc. evaluated properties representing 100% 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.

We recorded non-cash impairment charges on properties included in developed properties of $758, $4,962, $4,901, for the years ended December 31, 2014, 2013 and 2012, 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 $950, $30 and $87 for the years ended December 31, 2014, 2013 and 2012, 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 and 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

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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.

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, 2014, we reported a $6,478 mark-to-market gain 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 $789 for the year ended December 31, 2014.

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.

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 both a market condition and a performance condition, which requires management to estimate the likelihood of the market condition being achieved as of the date of the grant, and the likelihood of the performance condition being met at each reporting period end, based upon actual and expected future results.

We recognize stock-based 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.

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Valuation of Deferred Tax Assets

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). We have recorded a valuation allowance against certain deferred tax assets of $1,202 as of December 31, 2014. Some or all of this valuation allowance may be reversed in future periods against future income.

 

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, 2014, our income before income taxes would have decreased by $1,048 for each $0.50 change per Mcf in natural gas prices. Our income before income taxes would have decreased $20 for each $1.00 change per Bbl in oil prices for the year ended December 31, 2014. 

Interest Rate Risks

At December 31, 2014, we had a total of $47,515 outstanding under the Credit Facility ($50,000 borrowing base effective August 29, 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 3.1% at December 31, 2014. Assuming no change in the amount outstanding at December 31, 2014, the annual impact on interest expense for every 1.0% change in the average interest rate would be approximately $475 before taxes. Any balance outstanding on the credit facility matures on August 29, 2017.

 

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 our internal control over financial reporting as of December 31, 2014. 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, 2014.

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, 2014 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

None. 

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PART III

Pursuant to instruction G(3) to Form 10-K, the following Items 10,11,12,13 and 14 will be included in an amendment to this Form 10-K or in the Company’s definitive proxy statement for the 2015 annual meeting of stockholders to be filed within 120 days from December 31, 2014, and is incorporated by reference to this report. 

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Incorporated by reference from the definitive proxy statement for our 2015 annual meeting of stockholders, which will be filed no later than 120 days after December 31, 2014.

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.escaleraresources.com in the Corporate Governance section.

ITEM 11. EXECUTIVE COMPENSATION  

Incorporated by reference from the definitive proxy statement for our 2015 annual meeting of stockholders, which will be filed no later than 120 days after December 31, 2014.

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

Incorporated by reference from the definitive proxy statement for our 2015 annual meeting of stockholders, which will be filed no later than 120 days after December 31, 2014.

ITEM 13. CERTAIN RELATIONSHIPS, RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE

Incorporated by reference from the definitive proxy statement for our 2015 annual meeting of stockholders, which will be filed no later than 120 days after December 31, 2014.

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

Incorporated by reference from the definitive proxy statement for our 2015 annual meeting of stockholders, which will be filed no later than 120 days after December 31, 2014.

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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:

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*Filed with this Form 10-K.

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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.