bcei_Current Folio_10K

Table of Contents

 

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

OR

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

 

Commission file number: 001‑35371

Bonanza Creek Energy, Inc.

(Exact name of registrant as specified in its charter)

 

 

Delaware
(State or other jurisdiction of
incorporation or organization)

61‑1630631
(I.R.S. Employer Identification No.)

410 17th Street, Suite 1400 Denver, Colorado
(Address of principal executive offices)

80202
(Zip Code)

 

(720) 440‑6100

(Registrants telephone number, including area code)

Securities Registered Pursuant to Section 12(b) of the Act:

 

 

(Title of Class)

(Name of Exchange)

Common Stock, par value $0.001 per share

New York Stock Exchange

 

Securities Registered Pursuant to Section 12(g) of the Act: None

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 is not contained herein, and will not be contained, to the best of Registrants 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.

 

 

 

 

Large accelerated filer 

Accelerated filer 

Non‑accelerated filer 
(Do not check if a
smaller reporting company)

Smaller reporting company 

 

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

The aggregate market value of the registrants voting and non‑voting common equity held by non‑affiliates on June 30,  2014, based upon the closing price of $57.19 of the registrants common stock as reported on the New York Stock Exchange, was approximately $2,310,572,708. Excludes approximately 242,931 shares of the registrants common stock held by executive officers, directors and stockholders that the registrant has concluded, solely for the purpose of the foregoing calculation, were affiliates of the registrant.

Number of shares of registrants common stock outstanding as of February 24, 2015:  49,335,032

Documents Incorporated By Reference:

Portions of the registrants definitive proxy statement for its 2015 Annual Meeting of Stockholders, which will be filed with the Securities and Exchange Commission within 120 days of December 31, 2014, are incorporated by reference into Part III of this report for the year ended December 31, 2014.

 

 

 


 

BONANZA CREEK ENERGY, INC.

FORM 10‑K

FOR THE YEAR ENDED DECEMBER 31, 2014

TABLE OF CONTENTS

 

 

 

 

Glossary of Certain Definitions

6

 

PART I

 

Item 1. 

Business

13

Item 1A. 

Risk Factors

39

Item 1B. 

Unresolved Staff Comments

63

Item 2. 

Properties

63

Item 3. 

Legal Proceedings

63

Item 4. 

Mine Safety Disclosures

63

 

PART II

 

Item 5. 

Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

64

Item 6. 

Selected Financial Data

66

Item 7. 

Management’s Discussion and Analysis of Financial Condition and Results of Operations

67

Item 7A. 

Quantitative and Qualitative Disclosure about Market Risk

84

Item 8. 

Financial Statements and Supplementary Data

86

Item 9. 

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

115

Item 9A. 

Controls and Procedures

115

Item 9B. 

Other Information

117

 

PART III

 

Item 10. 

Directors, Executive Officers and Corporate Governance

118

Item 11. 

Executive Compensation

118

Item 12. 

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

118

Item 13. 

Certain Relationships and Related Transactions, and Director Independence

118

Item 14. 

Principal Accountant Fees and Services

118

 

PART IV

 

Item 15. 

Exhibits, Financial Statement Schedules

119

 

 

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Information Regarding Forward‑Looking Statements

This Annual Report on Form 10‑K contains various statements, including those that express belief, expectation or intention, as well as those that are not statements of historic fact, that are forward‑looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities and Exchange Act of 1934, as amended. When used in this Annual Report on Form 10‑K, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “may,” “continue,” “predict,” “potential,” “project,” “plan” “will,” and similar expressions are intended to identify forward‑looking statements, although not all forward‑looking statements contain such identifying words.

Forward‑looking statements include statements related to, among other things:

·

reserves estimates;

·

estimated sales volumes for 2015;

·

amount and allocation of forecasted capital expenditures and plans for funding capital expenditures and operating expenses;

·

ability to modify future capital expenditures;

·

the Wattenberg Field being a premier oil and resource play in the United States;

·

ability to increase sales volumes while lowering costs;

·

compliance with debt covenants;

·

ability to satisfy obligations related to ongoing operations;

·

compliance with government regulations;

·

adequacy of gathering systems and continuous improvement of such gathering systems;

·

impact from the lack of available gathering systems and processing facilities in certain areas;

·

natural gas, oil and natural gas liquid prices and factors affecting the volatility of such prices;

·

impact of lower commodity prices;

·

the ability to use derivative instruments to manage commodity price risk and ability to use such instruments in the future;

·

plans to drill or participate in wells including the intent to focus in specific areas or formations;

·

loss of any purchaser of our products;

·

our estimated revenues and losses;

·

the timing and success of specific projects;

·

our implementation of long reach laterals in the Wattenberg Field;

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·

our use of multi-well pads to develop the Niobrara and Codell formations;

·

intention to continue to optimize enhanced completion techniques and well design changes;

·

intentions with respect to working interest percentages;

·

management and technical team;

·

outcomes and effects of litigation, claims and disputes;

·

our business strategy;

·

expectation that the Niobrara B and C benches and the Codell formation will be the primary sources of future production growth;

·

our ability to replace oil and natural gas reserves;

·

impact of recently issued accounting pronouncements;

·

impact of the loss a single customer;

timing and ability to meet certain volume commitments related to purchase and transportation agreements;

the impact of customary royalty interests, overriding royalty interests, obligations incident to operating agreements, liens for current taxes and other industry-related constraints;

·

our financial position;

·

our cash flow and liquidity;

·

the adequacy of our insurance;

·

our ability to leverage current infrastructure and our operational expertise to integrate and develop the Wattenberg Field Acquisition;

·

intention to use the net proceeds of public offering of common stock on February 6, 2015 to repay all of the outstanding borrowings under the revolving credit facility and general corporate purposes; and

·

other statements concerning our operations, economic performance and financial condition.

We have based these forward‑looking statements on certain assumptions and analyses we have made in light of our experience and our perception of historical trends, current conditions and expected future developments as well as other factors we believe are appropriate under the circumstances. They can be affected by inaccurate assumptions or by known or unknown risks and uncertainties. Many such factors will be important in determining actual future results. The actual results or developments anticipated by these forward‑looking statements are subject to a number of risks and uncertainties, many of which are beyond our control, and may not be realized or, even if substantially realized, may not have the expected consequences. Actual results could differ materially from those expressed or implied in the forward‑looking statements.

Factors that could cause actual results to differ materially include, but are not limited to, the following:

·

the risk factors discussed in Part I, Item 1A of this Annual Report on Form 10‑K;

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·

declines or volatility in the prices we receive for our oil, natural gas liquids and natural gas;

·

general economic conditions, whether internationally, nationally or in the regional and local market areas in which we do business;

·

ability of our customers to meet their obligations to us;

·

our ability to generate sufficient cash flow from operations, borrowings or other sources to enable us to fully develop our undeveloped acreage positions;

·

the presence or recoverability of estimated oil and natural gas reserves and the actual future sales volume rates and associated costs;

·

uncertainties associated with estimates of proved oil and gas reserves and, in particular, probable and possible resources;

·

the possibility that the industry may be subject to future local, state, and federal regulatory or legislative actions (including additional taxes and changes in environmental regulation);

·

environmental risks;

·

seasonal weather conditions and lease stipulations;

·

drilling and operating risks, including the risks associated with the employment of horizontal drilling techniques;

·

our ability to acquire adequate supplies of water for drilling and completion operations;

·

availability of oilfield equipment, services and personnel;

·

exploration and development risks;

·

competition in the oil and natural gas industry;

·

management’s ability to execute our plans to meet our goals;

·

risks related to our derivative instruments;

·

our ability to attract and retain key members of our senior management and key technical employees;

·

our ability to maintain effective internal controls;

·

access to adequate gathering systems and pipeline take‑away capacity to provide adequate infrastructure for the products of our drilling program;

·

our ability to secure firm transportation for oil and natural gas we produce and to sell the oil and natural gas at market prices;

·

costs and other risks associated with perfecting title for mineral rights in some of our properties;

·

continued hostilities in the Middle East and other sustained military campaigns or acts of terrorism or sabotage; and

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·

other economic, competitive, governmental, legislative, regulatory, geopolitical and technological factors that may negatively impact our businesses, operations or pricing.

All forward‑looking statements speak only as of the date of this Annual Report on Form 10‑K. We disclaim any obligation to update or revise these statements unless required by law, and you should not place undue reliance on these forward‑looking statements. Although we believe that our plans, intentions and expectations reflected in or suggested by the forward‑looking statements we make in this Annual Report on Form 10‑K are reasonable, we can give no assurance that these plans, intentions or expectations will be achieved. We disclose important factors that could cause our actual results to differ materially from our expectations under Item 1A. Risk Factors and Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and elsewhere in this Annual Report on Form 10‑K. These cautionary statements qualify all forward‑looking statements attributable to us or persons acting on our behalf.

GLOSSARY OF OIL AND NATURAL GAS TERMS

We have included below the definitions for certain terms used in this Annual Report on Form 10‑K:

“3‑D seismic data” Geophysical data that depict the subsurface strata in three dimensions. 3‑D seismic data typically provide a more detailed and accurate interpretation of the subsurface strata than 2‑D, or two‑dimensional, seismic data.

“Analogous reservoir” Analogous reservoirs, as used in resources assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, an “analogous reservoir” refers to a reservoir that shares the following characteristics with the reservoir of interest:

(i)

Same geological formation (but not necessarily in pressure communication with the reservoir of interest);

(ii)

Same environment of deposition;

(iii)

Similar geological structure; and

(iv)

Same drive mechanism.

“Bbl” One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in reference to crude oil, condensate or natural gas liquids.

“Bcf” One billion cubic feet of natural gas.

“Boe” One stock tank barrel of oil equivalent, calculated by converting natural gas and natural gas liquids volumes to equivalent oil barrels at a ratio of six Mcf to one Bbl of oil.

“British thermal unit” or “BTU” The heat required to raise the temperature of a one‑pound mass of water from 58.5 to 59.5 degrees Fahrenheit.

“Basin” A large natural depression on the earth’s surface in which sediments generally brought by water accumulate.

“Completion” The process of treating a drilled well followed by the installation of permanent equipment for the production of crude oil or natural gas, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.

“Condensate” A mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.

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“Developed acreage” The number of acres that are allocated or assignable to productive wells or wells capable of production.

“Development costs” Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas. More specifically, development costs, including depreciation and applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to: (i) gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines, and power lines, to the extent necessary in developing the proved reserves; (ii) drill and equip development wells, development‑type stratigraphic test wells, and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly; (iii) acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices, and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems; and (iv) provide improved recovery systems.

“Development well” A well drilled within the proved area of a natural gas or oil reservoir to the depth of a stratigraphic horizon known to be productive.

“Differential” The difference between a benchmark price of oil and natural gas, such as the NYMEX crude oil spot, and the wellhead priced received.

“Deterministic method” The method of estimating reserves or resources using a single value for each parameter (from the geoscience, engineering or economic data) in the reserves calculation.

“Dry hole” Exploratory or development well that does not produce oil or gas in commercial quantities.

“Economically producible” The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. The value of the products that generate revenue shall be determined at the terminal point of oil and gas producing activities.

“Environmental assessment” A study that can be required pursuant to federal law to assess the potential direct, indirect and cumulative impacts of a project.

“ERISA” Employee Retirement Income Security Act of 1974.

Estimated ultimate recovery (EUR)” Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of that date.

“Exploratory well” A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or a stratigraphic test well.

“Extension well” A well drilled to extend the limits of a known reservoir.

“Field” An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field which are separated vertically by intervening impervious strata, or laterally by local geologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms “structural feature” and “stratigraphic condition” are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas‑of‑interest, etc.

“Finding and development costs” Calculated by dividing the amount of total capital expenditures for oil and natural gas activities, by the amount of estimated net proved reserves added through discoveries, extensions, infill drilling, acquisitions, and revisions of previous estimates less sales of reserves, during the same period.

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“Formation” A layer of rock which has distinct characteristics that differ from nearby rock.

“GAAP” Generally accepted accounting principles in the United States.

“HH” Henry Hub index.

“Horizontal drilling” A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at a right angle within a specified interval.

‘‘Hydraulic fracturing” The process of injecting water, proppant and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production.

“LIBOR” London interbank offered rate.

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

“MBoe” One thousand Boe.

“Mcf” One thousand cubic feet.

“MMBoe” One million Boe.

“MMBtu” One million British Thermal Units.

“MMcf” One million cubic feet.

“Net acres” The percentage of total acres an owner has out of a particular number of acres, or a specified tract. An owner who has 50% interest in 100 acres owns 50 net acres.

“Net production” Production that is owned by the registrant and produced to its interest, less royalties and production due others.    

“Net revenue interest” Economic interest remaining after deducting all royalty interests, overriding royalty interests and other burdens from the working interest ownership.

“Net well” Deemed to exist when the sum of fractional ownership working interests in gross wells equals one. The number of net wells is the sum of the fractional working interest owned in gross wells expressed as whole numbers and fractions of whole numbers.

“NGL” Natural gas liquid.

“NYMEX” The New York Mercantile Exchange.

“Oil and gas producing activities” defined as (i) the search for crude oil, including condensate and natural gas liquids, or natural gas in their natural states and original locations; (ii) the acquisition of property rights or properties for the purpose of further exploration or for the purpose of removing the oil or gas from such properties; (iii) the construction, drilling and production activities necessary to retrieve oil and gas from their natural reservoirs, including the acquisition, construction, installation, and maintenance of field gathering and storage systems, such as lifting the oil and gas to the surface and gathering, treating and field processing (as in the case of processing gas to extract liquid hydrocarbons); and (iv) extraction of saleable hydrocarbons, in the solid, liquid, or gaseous state, from oil sands, shale, coal beds, or other nonrenewable natural resources which are intended to be upgraded into synthetic oil or gas, and activities undertaken with a view to such extraction.

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“PDNP” Proved developed non-producing reserves.

“PDP” Proved developed producing reserves.

“Percentage-of-proceeds” A processing contract where the processor receives a percentage of the sold outlet stream, dry gas, NGLs or a combination, from the mineral owner in exchange for providing the processing services. In the Mid-Continent region, we are both a producer and, through ownership of gas plants, a processor, our sales volumes include volumes processed through the gas plants directly related to our working interest and volumes for which we are contractually entitled pursuant to the processing of gas from third party interests

“Play” A term applied to a portion of the exploration and production cycle following the identification by geologists and geophysicists of areas with potential oil and gas reserves.

“Plugging and abandonment” Refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another or to the surface. Regulations of many states require plugging of abandoned wells.

“Pooling” Pooling is a provision in an oil and gas lease that allows the operator to combine the leased property with properties owned by others. (Pooling is also known as unitization.) The separate tracts are joined to form a drilling unit. Ownership shares are issued according to the acreage contributed or by the production capabilities of each producing well for fields in later stages of development.

“Possible reserves” Those additional reserves that are less certain to be recovered than probable reserves.

“Probable reserves” Those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.

“Production costs” Costs incurred to operated and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities. They become part of the cost of oil and gas produced. Examples of production costs (sometimes called lifting costs) are (a) costs of labor to operate the wells and related equipment and facilities; (b) repairs and maintenance; (c) materials, supplies, and fuel consumed and supplies utilized in operating the wells and related equipment and facilities; (d) property taxes and insurance applicable to proved properties and wells and related equipment and facilities; and (e) severance taxes. Some support equipment or facilities may serve two or more oil and gas producing activities and may also serve transportation, refining, and marketing activities. To the extent that the support equipment and facilities are used in oil and gas producing activities, their depreciation and applicable operating costs become exploration, development or production costs, as appropriate. Depreciation, depletion, and amortization of capitalized acquisition, exploration, and development costs are not production costs but also become part of the costs of oil and gas produced along with production (lifting) costs identified above.

“Productive well” A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes.

“Proppant” Sized particles mixed with fracturing fluid to hold fractures open after a hydraulic fracturing treatment. In addition to naturally occurring sand grains, man‑made or specially engineered proppants, such as resin‑coated sand or high‑strength ceramic materials like sintered bauxite, may also be used. Proppant materials are carefully sorted for size and sphericity to provide an efficient conduit for production of fluid from the reservoir to the wellbore.

“Proved developed reserves” Proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well.

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“Proved reserves” Those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced, or the operator must be reasonably certain that it will commence the project, within a reasonable time.

(i)

The area of the reservoir considered as proved includes:

(a)

The area identified by drilling and limited by fluid contacts, if any, and

(b)

Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

(ii)

In the absence of data on fluid contracts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii)

Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher potions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv)

Reserves that can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(a)

Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based, and

(b)

The project has been approved for development by all necessary parties and entities, including governmental entities.

(v)

Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12‑month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first‑day‑of‑the‑month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

“Proved undeveloped reserves” or “PUD” 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. Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are schedule to be drilled within five years, unless specific circumstances justify a longer time. Under no circumstances shall estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.

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“PV‑10” A non‑GAAP financial measure that represents inflows from proved crude oil and natural gas reserves, less future development and production costs, discounted at 10% per annum to reflect timing of future cash inflows and using the twelve‑month unweighted arithmetic average of the first‑day‑of‑the‑month commodity prices (after adjustment for differentials in location and quality) for each of the preceding twelve months. See footnote (2) to the Proved Reserves table in Item 1. “Business” of this Annual Report on Form 10‑K for more information.

“Reasonable certainty” If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90 percent probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical and geochemical) engineering, and economic data are made to estimated ultimate recovery (“EUR”) with time, reasonably certain estimated ultimate recovery is much more likely to increase or remain constant than to decrease.

“Recompletion” The process of re‑entering an existing wellbore that is either producing or not producing and completing new reservoirs in an attempt to establish or increase existing production.

“Reserves” Estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

“Reserve replacement percentage” The sum of sales of reserves, reserve extensions and discoveries, reserve acquisitions, and reserve revisions of previous estimates for a specified period of time divided by production for that same period.

“Reservoir” A porous and permeable underground formation containing a natural accumulation of producible crude oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

“Resource play” Refers to drilling programs targeted at regionally distributed oil or natural gas accumulations. Successful exploitation of these reservoirs is dependent upon new technologies such as horizontal drilling and multi‑stage fracture stimulation to access large rock volumes in order to produce economic quantities of oil or natural gas.

“Royalty interest” An interest in an oil and natural gas property entitling the owner to a share of oil or gas production free of production costs, but subject to severance taxes (unless the owner is agreement agency).

“Sales volumes” All volumes for which a reporting entity is entitled to proceeds, including production, net to the reporting entity’s interest and third party production obtained from percentage-of-proceeds contracts and sold by the reporting entity.

“Service well” A service well is drilled or completed for the purpose of supporting production in an existing field. Wells in this class are drilled for the following specific purposes: gas injection, water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection for in-situ combustion.  

“Spacing” Regulation concerning the number of wells which can be drilled on a given area of land. Depending on the depth of the reservoir, one well may be allowed on a small area of five acres or on an area up to 640 acres. Typical spacing is 40 acres for oil wells and 640 acres for gas wells. Also referred to as “well spacing.”

“Three stream The separate reporting of NGLs extracted from the natural gas stream and sold as a separate product.

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“Undeveloped acreage” Those leased acres on which wells have not been drilled or completed to a point that would permit the production of economic quantities of oil or gas regardless of whether such acreage contains proved reserves.

“Undeveloped reserves” Undeveloped oil and gas reserves are reserves of any category 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. Also referred to as “undeveloped oil and gas reserves.”

“Working interest” The right granted to the lessee of a property to explore for and to produce and own oil, gas, or other minerals. The working interest owners bear the exploration, development, and operating costs on either a cash, penalty, or carried basis.

“Workover” Operations on a producing well to restore or increase production.

“WTI” West Texas Intermediate index.

 

 

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PART I

Item 1.  Business.

When we use the terms “Bonanza Creek,” the “Company,” “we,” “us,” or “our” we are referring to Bonanza Creek Energy, Inc. and its consolidated subsidiaries unless the context otherwise requires. We have included certain technical terms important to an understanding of our business under Glossary of Oil and Natural Gas Terms above. Throughout this document we make statements that may be classified as “forward‑looking.” Please refer to the Information Regarding Forward‑Looking Statements section above for an explanation of these types of statements.

Overview

Bonanza Creek is an independent energy company engaged in the acquisition, exploration, development and production of onshore oil and associated liquids‑rich natural gas in the United States. Our oil and liquids‑weighted assets are concentrated primarily in the Wattenberg Field in Colorado, which we have designated the Rocky Mountain region, and the Dorcheat Macedonia Field in southern Arkansas, which we have designated the Mid‑Continent region. In addition, we own and operate oil‑producing assets in the North Park Basin in Colorado and the McKamie Patton Field in southern Arkansas. The Wattenberg Field is one of the premier oil and gas resource plays in the United States benefiting from a low cost structure and strong production efficiencies. Our management team has extensive experience acquiring and operating oil and gas properties and significant expertise in horizontal drilling and fracture stimulation, which we believe will contribute to the development of our sizable inventory of projects, including those targeting the Niobrara and Codell formations in the Rocky Mountain region and oily Cotton Valley sands in the Mid-Continent region. We operate approximately 98% of our proved reserves with an average working interest of approximately 86% providing us with significant control over the rate of development of our asset base.

We are currently focused on the horizontal development of significant resource potential from the Niobrara and Codell formations in the Wattenberg Field and expect to invest approximately 90% of our 2015 capital budget in this field. The remaining 10% of our 2015 budget is allocated primarily to vertical development of the Dorcheat Macedonia Field in southern Arkansas, targeting oil‑rich Cotton Valley sands. We believe the location, scale and the contiguous nature of our acreage in both regions will allow the Company to increase sales volumes while lowering costs in our efforts to maximize the value of the resource potential. Our 2015 budget is expected to maintain the Company’s 2014 exit rate sales volumes through the full year, achieving approximately 15% annual growth on a year-over-year basis. In 2014, we successfully drilled 162 and completed 159 productive operated wells and participated in drilling 12 and completing 12 productive non‑operated wells. The resulting production rates achieved by this program increased sales volumes by 45% over the previous year to 23,519 Boe/d of which 70% was crude oil and natural gas liquids (“NGL”). We had 21 operated wells and three non-operated wells in progress as of December 31, 2014. Our sales volumes during the fourth quarter of 2014 were 25,893 Boe/d, a 23% increase over the comparable period in 2013.

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The following tables summarize our estimated proved reserves, PV-10 reserve value, sales volumes, and projected capital spend as of December 31, 2014:

 

 

 

 

 

 

 

 

 

 

 

    

 

    

 

    

Natural

    

 

 

 

 

Crude

 

Natural

 

Gas

 

Total

 

 

 

Oil

 

Gas

 

Liquids

 

Proved

 

Estimated Proved Reserves

 

(MBbls)

 

(MMcf)

 

(MBbls)

 

(MBoe)

 

Developed

 

 

 

 

 

 

 

 

 

Rocky Mountain

 

20,593 

 

65,282 

 

 

31,473 

 

Mid-Continent

 

7,750 

 

29,212 

 

2,199 

 

14,818 

 

 

 

28,343 

 

94,494 

 

2,199 

 

46,291 

 

Undeveloped

 

 

 

 

 

 

 

 

 

Rocky Mountain

 

23,556 

 

78,715 

 

 

36,675 

 

Mid-Continent

 

2,860 

 

15,342 

 

1,154 

 

6,571 

 

 

 

26,416 

 

94,057 

 

1,154 

 

43,246 

 

Total Proved

 

54,759 

 

188,551 

 

3,353 

 

89,537 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Sales Volumes for

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

the Year Ended

 

 

 

 

Net Proved

 

 

 

Estimated Proved Reserves at

 

December 31,

 

 

 

 

Undeveloped

 

 

 

December 31, 2014(1)

 

2014

 

 

 

 

Drilling

 

 

 

 

 

 

 

 

 

 

 

 

Average Net

 

 

 

Projected

 

Locations

 

 

 

Total

 

 

 

 

 

 

 

 

Daily Sales

 

 

 

2015 Capital

 

as of

 

 

 

Proved

 

% of

 

% Proved

 

PV-10

 

Volumes

 

% of

 

Expenditures

 

December 31,

 

 

 

(MBoe)

   

Total

 

Developed

 

($ in MM)(2)

   

(Boe/d)

   

Total

 

($ in millions)

   

2014

 

Rocky Mountain

 

68,148

 

76 

%

46 

%

$

986.7 

 

17,531 

 

75 

%

$

380 

 

188.8 

 

Mid-Continent(3)

 

21,389

 

24 

%

69 

%

 

353.8 

 

5,978 

 

25 

%

 

40 

 

71.5 

 

California

 

 

%

%

 

 

10 

 

%

 

 

 

 

Total

 

89,537

 

100 

%

52 

%

$

1,340.5 

 

23,519 

 

100 

%

$

420 

 

260.3 

 


(1)

Proved reserves and related future net revenue and PV‑10 were calculated using prices equal to the twelve‑month unweighted arithmetic average of the first‑day‑of‑the‑month commodity prices for each of the preceding twelve months, which were $94.99 per Bbl WTI and $4.35 per MMBtu HH. Adjustments were then made for location, grade, transportation, gravity, and Btu content, which resulted in a decrease of $10.71 per Bbl of crude oil and an increase of $0.89 per MMBtu of natural gas.

(2)

PV‑10 is a non‑GAAP financial measure and represents the present value of estimated future cash inflows from proved crude oil and natural gas reserves, less future development and production costs, discounted at 10% per annum to reflect timing of future cash inflows using the twelve‑month unweighted arithmetic average of the first‑day‑of‑the‑month commodity prices, after adjustment for differentials in location and quality, for each of the preceding twelve months. We believe that PV‑10 provides useful information to investors as it is widely used by professional analysts and sophisticated investors when evaluating oil and gas companies. We believe that PV‑10 is relevant and useful for evaluating the relative monetary significance of our reserves. Professional analysts and sophisticated investors may utilize the measure as a basis for comparison of the relative size and value of our reserves to other companies’ reserves. 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 in evaluating the Company and our reserves. PV‑10 is not intended to represent the current market value of our estimated reserves. PV‑10 differs from Standardized Measure of Discounted Future Net Cash Flows (“Standardized Measure”) because it does not include the effect of future income taxes. Please refer to the Reconciliation of PV‑10 to Standardized Measure presented several pages below.

(3)

Mid-Continent sales volumes were 5,978 Boe/d for 2014, which is comprised of 5,388 Boe/d of production net to our interest and 590 Boe/d sales volumes from our percentage-of-proceeds contracts.

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Our History

Bonanza Creek Energy, Inc. was incorporated on December 2, 2010 pursuant to the laws of the State of Delaware. On December 23, 2010, in connection with an investment from Project Black Bear LP, an entity advised by West Face Capital Inc. (“West Face Capital”) and certain clients of Alberta Investment Management Corporation (“AIMCo”), we acquired Bonanza Creek Energy Company, LLC (“BCEC”) and Holmes Eastern Company, LLC (“HEC”), which transactions we refer to as our “Corporate Restructuring.” We completed the initial public offering of our common stock in December 2011 (our “IPO”) pursuant to which 10,000,000 shares of our common stock were sold.

Our Business Strategies

Our primary goal is to increase stockholder value by investing capital in projects that provide attractive rates of return, and increase our sales volumes, proved reserves and cash flow. We intend to accomplish this by focusing on the following key strategies:

·

Increase Sales Volumes from Wattenberg Horizontal Opportunities and Develop Additional Resource Potential in Both of our Core Areas.  We expect to continue to generate profitable, long‑term reserve and production growth predominantly through repeatable, lower‑risk development drilling on our assets, which have multiple resource horizons. We intend to develop the Niobrara and Codell formations by drilling multi-well pads that utilize horizontal drilling and multi-stage fracturing in order to reduce surface use disturbance and to optimize efficiencies related to drilling and completion times, shared use of production facilities and overall resources recovery. We also expect to increase our implementation of long reach laterals (greater than 4,000 feet) to further reduce the number of surface locations needed to develop the Wattenberg Field.

·

Maintain High Degree of Operatorship.  We currently have and intend to maintain a high working interest in our assets, thereby allowing us to leverage our technical, operating and management skills and control the timing of our capital expenditures.

·

Manage Risk Exposure.  In order to achieve more predictable cash flow and to reduce our exposure to adverse fluctuations in oil prices, we have entered into and intend in the future to enter into derivative contracts for a significant portion of our expected sales volumes.

·

Pursue Ongoing Corporate Growth.  The Company engages in prudent evaluation of potential acquisitions where we can take advantage of our core operational and engineering competencies. 

Our Competitive Strengths

We believe the following combination of strengths will enable us to implement our strategies:

·

High Quality Asset Base with Oil and Liquids‑Weighted Growth.  As of December 31, 2014, we have accumulated approximately 70,000 net acres in the Wattenberg Field prospective for the Niobrara formation, of which, approximately 29,000 net acres are estimated to be prospective for the Codell formation. Our acreage is in an area noted for its high net oil and liquids content, with oil and NGLs comprising approximately 65% of proved reserves and approximately 70% of current sales volumes. We and other operators have consistently reported positive results in this area and believe our acreage position contains a large potential inventory of high value, ready‑to‑drill potential locations. Gathering systems and takeaway capacity in place in this area are continuously improving, enabling reduced time periods from well completion to first product sales.

·

Contiguous Nature of Our Leasehold.  Our acreage positions in the Wattenberg Field and in the Mid‑Continent region are highly contiguous allowing for more efficient field operations. In the Wattenberg Field, we believe our leasehold is particularly advantaged for development with horizontal wells and extended reach laterals.

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·

High Degree of Operational Control.  We operate approximately 98% of our proved reserves with an average working interest of approximately 86% providing us with significant control over the rate of development of our asset base. This allows us to employ the drilling and completion techniques we believe to be most effective, manage costs and control the timing and allocation of our capital expenditures.

·

Gas Processing Capability in southern Arkansas.  We own three gas processing facilities and 150 miles of gathering pipeline that principally serve our production from the Dorcheat Macedonia Field and our McKamie Patton Field properties. We believe the ownership of this gathering and processing infrastructure allows us to better control the timing of the development of our reserves, allows for high-grade drilling and improves our economics in southern Arkansas.

·

Experienced Management Team with Proven Track Record.  Our senior management team has extensive experience in the oil and gas industry. We believe our management and technical team is one of our principal competitive strengths due to their proven track record in execution and development of resource conversion opportunities. In addition, this team possesses substantial expertise in horizontal drilling techniques and fracture stimulation.

·

Completion Techniques. We have tested various completion techniques, including increasing the number of fracture stimulation stages from 18 to 28, resulting in shorter fracture densities, and higher concentration of proppant near the wellbore. We have also significantly increased our application of longer laterals. We have seen encouraging results from these enhanced completion techniques and well design changes, and will continue to optimize those techniques to deliver improved results.  

·

Financial Flexibility.  Our capital structure is intended to provide a high degree of financial flexibility to grow our asset base, both through organic projects and opportunistic acquisitions. Our liquidity as of December 31, 2014 was approximately $545.6 million, which was comprised of $543 million of availability under our senior secured revolving credit facility (“revolving credit facility”), if we elect to take advantage of our entire borrowing base (without giving effect to any scheduled or interim redetermination), and approximately $2.6 million of cash on hand. On February 6, 2015, the Company completed a public offering of 8,050,000 shares of common stock which generated net proceeds of approximately $202.6 million, after deducting underwriter discounts, commissions and estimated offering costs of $6.7 million. We have $14.0 million budgeted for leasehold, which limits non-discretionary spending. We currently do not have any long-term rig, fracture stimulation or sand commitments that would decrease the flexibility of our capital spending program. We also employ a disciplined approach to manage leverage and govern our organic capital spending programs. Please refer to Note 7-Long-Term Debt in Part II, Item 8 of this Annual Report on Form 10-K for additional discussion on our revolving credit facility.

Our Operations

Our operations are mainly focused in the Wattenberg Field in the Rocky Mountain region and in the Dorcheat Macedonia Field in the Mid‑Continent region.

Rocky Mountain Region

The two main areas in which we operate in the Rocky Mountain region are the Wattenberg Field in Weld County, Colorado and the North Park Basin in Jackson County, Colorado. As of December 31, 2014, our estimated proved reserves in the Rocky Mountain region were 68,148 MBoe, which represented 76% of our total estimated proved reserves and contributed 17,531 Boe/d of sales volumes during 2014.

Wattenberg Field—Weld County, Colorado.  Our operations are in the oil and liquids‑weighted extension area of the Wattenberg Field targeting the Niobrara and Codell formations. As of December 31, 2014, our Wattenberg position consisted of approximately 97,000 gross (70,000 net) acres. During 2014, we had a net increase of approximately 34,500 net acres in the Wattenberg Field.  We own 3‑D seismic surveys covering the majority of our acreage in the Wattenberg Field, which helps provide efficient and targeted horizontal drilling operations.

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The Wattenberg Field is now primarily developed for the Niobrara and Codell formations using horizontal drilling and multi‑stage fracture stimulation techniques. We believe the Niobrara B and C benches have been fully delineated on our legacy acreage, while the Codell formation continues to be delineated in our eastern legacy acreage. Our newly acquired acreage located north and south of the legacy acreage contains economic producing wells but will require additional drilling for full delineation. We expect these horizons to be the primary source of future production growth.

Our estimated proved reserves at December 31, 2014 in the Wattenberg Field were 67,849 MBoe. As of December 31, 2014, we had a total of 433 gross producing wells, of which 295 gross were horizontal wells, and our sales volumes during 2014 were 17,531 Boe/d, 95% of which came from horizontal wells. Our sales volumes for the fourth quarter of 2014 were 20,038 Boe/d. Our working interest for all producing wells averages approximately 82% and our net revenue interest is approximately 67%.

We continue to expand our proved reserves in this area by drilling non‑proved horizontal locations. As of December 31, 2014, we have an identified drilling inventory of approximately 226 gross (189 net) proved undeveloped (“PUD”) drilling locations on our acreage with average well costs of $4.2 million. During 2014, we drilled 114  horizontal wells and completed 109.

During 2014, in the Niobrara B bench, we drilled 53 and completed 54 standard length (approximately 4,000 foot lateral) horizontal wells, three extended reach horizontal wells with an average lateral length of 9,280 feet, and four medium reach horizontal wells with an average lateral length of 6,514 feet that we plan to complete in 2015. Since we began our horizontal Niobrara B bench drilling program in 2011, through December 31, 2014, we have drilled and completed 156 wells of which 133 are on 80‑acre spacing (six are extended reach lateral horizontal wells), three are on 60-acre spacing and 20 are on 40‑acre spacing. We believe the results demonstrated by our wells spaced at 60 and 40 acres warrant continued development of the Niobrara B bench at 60 and 40-acre spacing. In addition, we believe the shallower decline curves demonstrated by our extended reach laterals warrant continued testing of lateral lengths greater than 4,000 feet.

During 2014, in the Niobrara C bench, we drilled 33 and completed 35 standard length (approximately 4,000 foot lateral) horizontal wells, one extended reach horizontal well with a lateral length of 9,114 feet and two medium reach horizontal wells with an average lateral length of 6,600 feet that we plan to complete in 2015. Since we began our horizontal Niobrara C bench drilling program in 2012, through December 31, 2014, we have drilled and completed 41 wells of which 35 are on 80‑acre spacing (one an extended reach lateral horizontal well), two are on 60-acre spacing and four are on 40‑acre spacing. We believe the results demonstrated by our wells spaced at 60 and 40 acres warrant continued development of the Niobrara C bench at 60 and 40-acre spacing. In addition, we believe the results of slower decline curves demonstrated by our extended reach lateral well warrants continued testing of lateral lengths greater than 4,000 feet. Late in the year, the Company drilled and completed one standard length horizontal well in the Niobrara A bench.

During 2014, in the Codell formation, we drilled 16 and completed 14 standard length (approximately 4,000 foot lateral) horizontal wells and one medium reach horizontal well with a lateral length of 6,931 feet. Since we began our horizontal Codell drilling program in 2012, through December 31, 2014, we have drilled and completed 19 wells on 160-acre spacing of which one is a medium reach lateral horizontal well. We believe the results of the medium reach lateral well warrants continued testing of lateral lengths of greater than 4,000 feet.

We estimate our capital expenditures in the Wattenberg Field for 2015 will be $380 million, which includes drilling and completing 37 horizontal wells in the Niobrara B bench, 33 horizontal wells in the Niobrara C bench and 7 horizontal wells in the Codell sandstone. The Company expects well costs to contract in the near term, targeting an average of approximately $4.0 million for a 4,000 foot lateral, down from $4.5 million in 2014, and $6.75 million for a 9,000 foot lateral, down from $7.5 million in 2014. The drilling program calls for the application of extended reach laterals for approximately 29% of the total program. The Company has allocated approximately $40 million to non-well capital, including $14 million to maintain leases and the remainder on essential infrastructure projects.

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North Park Basin—Jackson County, Colorado.  We control approximately 22,000 gross (17,000 net) acres in the North Park Basin in Jackson County, Colorado, all prospective for the Niobrara oil shale. We operate the North and South McCallum Fields, which currently produce light oil and carbon dioxide (“CO2”) from the Dakota/Lakota Group sandstones and oil from a shallow waterflood in the Pierre B sandstone. Oil production is trucked to market, while CO2 production is gathered to a nearby plant for processing.

In the North Park Basin, our estimated proved reserves as of December 31, 2014 were approximately 299 MBoe, 100% of which were crude oil. None of our CO2 production is currently reflected in our reserve reports. During 2014, we drilled and successfully cored one vertical well which is currently being analyzed to determine a development plan for the basin. 

Currently, there is no takeaway capacity for natural gas from the North Park Basin. Any future commercial development of the Niobrara shale in this area will require significant investment to construct the infrastructure necessary to gather and transport the produced associated natural gas. None of our 2015 capital budget is assigned to the North Park Basin.

Mid‑Continent Region

In southern Arkansas, we target the oil‑rich Cotton Valley sands in the Dorcheat Macedonia and McKamie Patton Fields. As of December 31, 2014, our estimated proved reserves in the Mid-Continent region were 21,389 MBoe, 65% of which were oil and natural gas liquids and 69% of which were proved developed. We currently operate 277 producing vertical wells and, as of December 31, 2014, have an identified drilling inventory of approximately 86 gross (71.5 net) PUD drilling locations on our acreage with an average well cost of $1.8 million. During 2014, we drilled 48 wells and successfully completed 50 operated wells in the Mid-Continent region. We achieved a sales volume rate for 2014 of 5,978 Boe/d, of which 69% was from oil and NGLs, and a sales volume rate for the fourth quarter of 2014 of 6,538 Boe/d. Productive reservoirs range in depth from 4,500 to 9,000 feet. Those reservoirs include the Smackover and the Pettet, but our primary development target is the Cotton Valley. We budgeted capital expenditures for 2015 of approximately $40 million to drill 26 gross operated wells and perform approximately 70 recompletions.

Dorcheat Macedonia.  In the Dorcheat Macedonia Field, we average an approximate 83% working interest and an approximate 68% net revenue interest on all producing wells,  and the majority of our acreage is held by unitization, production, or drilling operations. We have approximately 243 gross producing wells and our production during 2014 was approximately 5,136 Boe/d (5,726 Boe/d sales volumes). During the fourth quarter of 2014, our production was 5,694 Boe/d (6,284 Boe/d sales volumes). Our proved reserves in this field are approximately 19,880 MBoe. During 2014, we continued to see positive test results from our 5-acre spacing project.

As of December 31, 2014, we have identified approximately 84 gross (70 net) PUD drilling locations on our acreage in this area. During 2014, we drilled 48 and successfully completed 50 vertical Cotton Valley wells in the Dorcheat Macedonia Field. In 2015, we expect to drill 21 PUD locations on 10‑acre spacing with a complete cost per well of approximately $1.8 million. In addition, we expect to drill three wells on 5‑acre spacing and perform approximately 70 recompletions on existing wells.

Other Mid‑Continent.  We own additional interests in the McKamie Patton Field in the Mid‑Continent region near the Dorcheat Macedonia Field. As of December 31, 2014, our estimated proved reserves were approximately 1,509 MBoe, and sales volume during 2014 was approximately 252 Boe/d.

Gas Processing Facilities.  Our Mid‑Continent gas processing facilities are located in Lafayette and Columbia counties in Arkansas and are strategically located to serve our production in the region. In the aggregate, our Arkansas gas processing facilities have approximately 40 MMcf/d of capacity with 86,000 gallons per day of associated natural gas liquids capacity. Our ownership of these facilities and related gathering pipeline provides us with the benefit of controlling processing and compression of our natural gas production and timing of connection to our newly completed wells.

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Reserves

Estimated Proved Reserves

The summary data with respect to our estimated proved reserves presented below has been prepared in accordance with rules and regulations of the Securities and Exchange Commission (the “SEC”) applicable to companies involved in oil and natural gas producing activities. Our reserve estimates do not include probable or possible reserves, categories which SEC rules do permit us to disclose in public reports. Our estimated proved reserves for the years ended December 31, 2014, 2013 and 2012 were determined using the preceding twelve‑months’ unweighted arithmetic average of the first‑day‑of‑the‑month prices. For a definition of proved reserves under the SEC rules, please see the Glossary of Oil and Natural Gas Terms included in the beginning of this report.

Reserve estimates are inherently imprecise and estimates for new discoveries are more imprecise than reserve estimates for producing oil and gas properties. Accordingly, these estimates are expected to change as new information becomes available. The PV‑10 values shown in the following table are not intended to represent the current market value of our estimated proved reserves. Neither prices nor costs have been escalated. The actual quantities and present values of our estimated proved reserves may be less than we have estimated.

The table below summarizes our estimated proved reserves at December 31, 2014, 2013 and 2012 for each of the regions and currently producing fields in which we operate. The proved reserve estimates at December 31, 2014 are based on reports prepared by our internal corporate reservoir engineering group, of which 100% were audited by Netherland, Sewell & Associates, Inc. (“NSAI”), our third party independent reserve engineers.  The proved reserve estimates at December 31, 2013 and 2012 are based on reports prepared by  NSAI and Cawley, Gillespie & Associates, Inc., respectively. In preparing these reports, NSAI and Cawley, Gillespie & Associates, Inc. evaluated 100% of our estimated proved reserves. For more information regarding our independent reserve engineers, please see Independent Reserve Engineers below. The information in the following table does not give any effect to or reflect our commodity derivatives.

 

 

 

 

 

 

 

 

 

 

At December 31,

 

Region/Field

 

2014

 

2013

 

2012

 

 

 

(MMBoe)

 

Rocky Mountain

    

68.1 

    

49.1 

    

32.4 

 

Wattenberg

 

67.8 

 

48.8 

 

31.9 

 

North Park

 

0.3 

 

0.3 

 

0.5 

 

Mid-Continent

 

21.4 

 

20.7 

 

20.6 

 

Dorcheat Macedonia

 

19.9 

 

19.4 

 

19.0 

 

McKamie Patton

 

1.5 

 

1.3 

 

1.6 

 

Total

 

89.5 

 

69.8 

 

53.0 

 

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The following table sets forth more information regarding our estimated proved reserves at December 31, 2014, 2013 and 2012:

 

 

 

 

 

 

 

 

 

 

At December 31,

 

 

 

2014

 

2013

 

2012

 

Reserve Data(1):

    

    

    

    

    

    

 

Estimated proved reserves:

 

 

 

 

 

 

 

Oil (MMBbls)

 

54.7 

 

43.6 

 

30.2 

 

Natural gas (Bcf)

 

188.6 

 

139.6 

 

118.5 

 

Natural gas liquids (MMBbls)

 

3.4 

 

2.9 

 

3.1 

 

Total estimated proved reserves (MMBoe)(2)

 

89.5 

 

69.8 

 

53.0 

 

Percent oil and liquids

 

65 

%  

67 

%  

63 

%

Estimated proved developed reserves:

 

 

 

 

 

 

 

Oil (MMBbls)

 

28.3 

 

20.7 

 

14.3 

 

Natural gas (Bcf)

 

94.5 

 

59.2 

 

48.9 

 

Natural gas liquids (MMBbls)

 

2.2 

 

1.6 

 

1.3 

 

Total estimated proved developed reserves (MMBoe)(2)

 

46.3 

 

32.2 

 

23.8 

 

Percent oil and liquids

 

66 

%  

69 

%  

66 

%

Estimated proved undeveloped reserves:

 

 

 

 

 

 

 

Oil (MMBbls)

 

26.4 

 

22.9 

 

15.8 

 

Natural gas (Bcf)

 

94.1 

 

80.4 

 

69.6 

 

Natural gas liquids (MMBbls)

 

1.2 

 

1.3 

 

1.8 

 

Total estimated proved undeveloped reserves (MMBoe)(2)

 

43.2 

 

37.6 

 

29.2 

 

Percent oil and liquids

 

64 

%  

64 

%  

60 

%


(1)

Proved reserves were calculated using prices equal to the twelve‑month unweighted arithmetic average of the first‑day‑of‑the‑month prices for each of the preceding twelve months, which were $94.99 per Bbl WTI and $4.35 per MMBtu HH, $96.91 per Bbl WTI and $3.67 per MMBtu HH, and $94.71 per Bbl WTI and $2.76 per MMBtu HH for the years ended December 31, 2014, 2013 and 2012, respectively. Adjustments were made for location and grade.

(2)

Determined using the ratio of 6 Mcf of natural gas being equivalent to one Bbl of crude oil.

Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped oil and gas reserves are 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 completion. Proved undeveloped reserves on undrilled acreage are limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic productivity at greater distances. All proved undeveloped locations in our December 31, 2014 reserves report are included in our development plan and are scheduled to be drilled within five years from their initial proved booking date. The Company’s financial group evaluated the proved undeveloped drilling plan using the Company’s current budget price deck and determined that the internally generated cashflows over the next five years would sufficiently fund the proved undeveloped development program. The reliable technologies used to establish our proved reserves are a combination of pressure performance, geologic mapping, offset productivity, electric logs, and production data.

 

Estimated proved reserves at December 31, 2014 were 89.5 MMBoe, a 28% increase from estimated proved reserves of 69.8 MMBoe at December 31, 2013. The net increase in reserves of 19.7 MMBoe is the result of additions in extensions and discoveries of 20.2 MMBoe, primarily due to the development of the Niobrara B and C benches and the Codell formations in the Wattenberg Field, coupled with a net positive revision of 7.1 MMBoe (engineering and pricing) and net acquisitions (acquisitions less divestitures) of 0.8 MMBoe offset by 8.4 MMBoe in production. The addition in extension and discoveries is primarily the result of drilling and completing 99 unproved horizontal locations (including 12 non-operated) in the Niobrara and the Codell formations in the Wattenberg Field during 2014 and the addition of 37 new horizontal proved undeveloped locations directly offsetting new wells brought online in 2014. As of December 31, 2014, approximately 70% of our horizontal development in the Wattenberg Field was in the Niobrara B formation, the

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majority of which was on 80-acre spacing. The net positive engineering revision is primarily the result of adding new Niobrara B proved undeveloped locations on 80-acre spacing, directly offsetting economic proved producing Niobrara B wells drilled prior to 2014, diagonal offsets to economic Niobrara B proved producing wells and a relatively small number of locations greater than one offset to economic Niobrara B proved producing wells but within developed areas and surrounded by Niobrara B proved producing wells. A total of 119 horizontal proved undeveloped locations were added to the proved reserves at December 31, 2014 of which 86 (72%) were direct offsets to economic proved producing wells (drilled in 2014 or prior to 2014), 21 (18%) were direct offsets in a diagonal pattern to economic proved producing wells and 12 (10%) were greater than one offset from economic proved producing wells. The reasonable certainty of the reserves associated with the latter two categories of proved undeveloped locations is based on analysis of the immediate surrounding productivity of the Niobrara B bench and detailed geologic mapping. All Niobrara proved undeveloped locations are spaced on 80 acres although testing is ongoing on 60-acre and 40-acre spacing. The positive engineering revision was offset by a small negative performance revision of approximately 540 MBoe. A negative pricing revision of 0.25 MMBoe resulted from a decrease in average commodity price from $96.91 per Bbl WTI and $3.67 per MMBTU HH for the year ended December 31, 2013 to $94.99 per Bbl WTI and $4.35 per MMBTU HH for the year ended December 31, 2014.

Estimated proved reserves at December 31, 2013 were 69.8 MMBoe, a 32% increase from estimated proved reserves of 53.0 MMBoe at December 31, 2012. The net increase in reserves of 16.8 MMBoe resulting from development in the Wattenberg Field was comprised of 28.9 MMBoe of additions in extensions and discoveries offset by 3.8 MMBoe in sales volumes and negative revisions of 8.3 MMBoe. The negative revision results primarily from a combination of eliminating 45 net vertical locations from proved undeveloped due to the change in focus from vertical to horizontal development, the elimination of all proved non‑producing reserves associated with vertical well refracs, recompletions, and lower performance from our vertical producers due to increased line pressure. The addition in extension and discoveries is the result of drilling and completing 68 unproved horizontal locations (including 4 non‑operated) in the Wattenberg Field during 2013 and the addition of 89 new horizontal proved undeveloped locations. A net increase in reserves of 0.1 MMBoe in the Mid‑Continent region resulted from the drilling and completion of our 5 acre increased density pilots in the Cotton Valley formation offset by a negative revision resulting from lower than expected proved developed performance. A small positive pricing revision of 0.51 MMBoe resulted from an increase in average commodity price from $94.71 per Bbl WTI and $2.76 per MMBtu HH for the year ended December 31, 2012 to $96.91 per Bbl WTI and $3.67 per MMBtu HH for the year ended December 31, 2013.

Estimated proved reserves at December 31, 2012 were 53.0 MMBoe, a 21% increase from estimated proved reserves of 43.7 MMBoe at December 31, 2011. The net increase in reserves of 9.3 MMBoe resulted from development in the Wattenberg Field was comprised of 18.9 MMBoe of additions in extensions and discoveries offset by 3.5 MMBoe in sales volumes and negative revisions of 6.1 MMBoe. The negative revision resulted from a combination of eliminating 50 locations from proved undeveloped due to the change in focus from vertical to horizontal development and lower performance from our vertical producers. The addition in extension and discoveries was the result of drilling and completing 65 unproved locations in the Wattenberg Field during 2012 (approximately 50% horizontal Niobrara B bench locations, 50% vertical development) and the addition of 63 new proved undeveloped locations (100% horizontal Niobrara B bench locations). A net increase in reserves of 0.68 MMBoe in the Mid‑Continent region resulted from continued development of the Cotton Valley formation. Proved reserves decreased by 0.67 MMBoe with the divestiture of the majority of our California properties. A small negative pricing revision of 0.1 MMBoe resulted from a decrease in commodity price from $96.19 per Bbl WTI and an average price of $4.12 per MMBtu HH for the year ended December 31, 2011 to $94.71 per Bbl WTI and $2.76 per MMBtu HH for the year ended December 31, 2012.

Reconciliation of PV‑10 to Standardized Measure

PV‑10 is derived from the Standardized Measure, which is the most directly comparable GAAP financial measure. PV‑10 is a computation of the Standardized Measure on a pre‑tax basis. PV‑10 is equal to the Standardized Measure at the applicable date, before deducting future income taxes, discounted at 10%. We believe that the presentation of PV‑10 is relevant and useful to investors because it presents the discounted future net cash flows attributable to our estimated net proved reserves prior to taking into account future corporate income taxes, and it is a useful measure for evaluating the relative monetary significance of our oil and natural gas properties. Further, investors may utilize the measure as a basis for comparison of the relative size and value of our reserves to other companies. We

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use this measure when assessing the potential return on investment related to our oil and natural gas properties. PV‑10, however, is not a substitute for the Standardized Measure. Our PV‑10 measure and the Standardized Measure do not purport to present the fair value of our oil and natural gas reserves.

The following table provides a reconciliation of PV‑10 to Standardized Measure at December 31, 2014, 2013 and 2012:

 

 

 

 

 

 

 

 

 

 

 

 

 

December 31,

 

 

 

2014

 

2013

 

2012

 

 

 

(in millions)

 

PV-10

    

$

1,340.5 

    

$

1,227.2 

    

$

834.7 

 

Present value of future income taxes discounted at 10%

  

 

(233.1)

 

 

(301.9)

 

 

(151.3)

 

Standardized Measure

 

$

1,107.4 

 

$

925.3 

 

$

683.4 

 

Proved Undeveloped Reserves

 

 

 

 

 

 

 

 

 

 

Net Reserves, MBoe

 

 

 

At December 31,

 

 

 

2014

 

2013

 

2012

 

Beginning of year

    

37,603 

 

29,192 

 

26,652 

 

Converted to proved developed

 

(7,791)

 

(3,047)

 

(5,166)

 

Additions from capital program

 

5,596 

 

16,535 

 

13,913 

 

Acquisitions (sales)

 

 

1,779 

 

(430)

 

Revisions

 

7,838 

 

(6,856)

 

(5,777)

 

End of year

 

43,246 

 

37,603 

 

29,192 

 

 

At December 31, 2014, our proved undeveloped reserves were 43,246 MBoe, all of which are scheduled to be drilled within five years of their initial proved date. During 2014, the Company converted 21% of its proved undeveloped reserves (58 wells, 7,791 MBoe) at a cost of $116.9 million. Executing our 2014 capital program resulted in the addition of 5,596 MBoe (45 wells) in proved undeveloped reserves. The positive engineering revision of 7,838 MBoe was primarily the result of adding 49 new proved undeveloped locations in Wattenberg on 80-acre spacing, directly offsetting economic proved producing wells drilled prior to 2014, 21 diagonal offsets to economic proved producing wells and 12 proved undeveloped locations positioned greater than one offset to economic proved producing wells but within developed areas and surrounded by proved producing wells. Also included in the revision category was the removal from proved undeveloped locations of 15 horizontal locations in the Wattenberg Field that were no longer spaced on 80 acres following the 2014 capital drilling program and all of the vertical proved undeveloped locations in the Wattenberg Field which have been replaced by horizontal wells or are expected to be replaced in the future. Proved undeveloped locations remaining in the category from December 31, 2013 received a downward revision of 214 Mboe.

 

At December 31, 2013, our proved undeveloped reserves were 37,603 MBoe, all of which were scheduled to be drilled within five years of their initial disclosure. During 2013, 3,047 MBoe or 10% of our proved undeveloped reserves (40 wells) were converted into proved developed reserves requiring $62.8 million of drilling and completion capital. Continued delineation and testing in our Wattenberg Field in 2013 resulted in a conversion rate less than 20% for the year. Execution of our 2013 capital program resulted in the addition of 16,535 MBoe in proved undeveloped reserves (92 wells). The negative revision of 6,856 MBoe resulted from a combination of eliminating vertical proved undeveloped locations in the Wattenberg Field continuing the transition to horizontal development and a reduction in proved undeveloped reserves in the Dorcheat Macedonia Field based on proved developed performance.

At December 31, 2012, our proved undeveloped reserves were 29,192 MBoe, all of which were scheduled to be drilled within five years of their initial disclosure. During 2012, 5,166 MBoe or 19.4% of our proved undeveloped reserves (89 wells) were converted into proved developed reserves requiring $128.9 million of drilling and completion capital and $16.2 million of capital primarily used to expand our Dorcheat Macedonia gas plant. Executing our 2012 capital program resulted in the addition of 13,913 MBoe in proved undeveloped reserves (83 wells). Sales of the majority of our California properties during 2012 reduced our proved undeveloped reserves by 430 MBoe. The negative revision

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of 5,777 MBoe results from a combination of eliminating 50 locations in the Wattenberg Field from proved undeveloped due to the change in focus from vertical to horizontal development and the reduction in remaining vertical proved undeveloped reserves as a result of lower performance from our vertical producers.

Internal controls over reserves estimation process

Our policies regarding internal controls over the recording of reserves estimates require reserves to be in compliance with the SEC definitions and guidance and prepared in accordance with Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. The Company’s Reserve Committee reviews significant reserve changes on an annual basis and our third party independent reserve engineers, NSAI, is engaged by and has direct access to the Reserve Committee. NSAI audited 100% of our estimated proved reserves at December 31, 2014 and evaluated 100% of our estimated proved reserves in the preparation of our reserve report at December 31, 2013. Cawley, Gillespie & Associates, Inc. evaluated 100% of our estimated proved reserves in the preparation of our reserve report at December 31, 2012.

Responsibility for compliance in reserves estimation is delegated to our internal corporate reservoir engineering group managed by Lynn E. Boone. Ms. Boone is our Senior Vice President, Planning & Reserves. Ms. Boone attended the Colorado School of Mines and graduated in 1982 with a Bachelor of Science degree in Chemical and Petroleum Refining Engineering. She attended the University of Oklahoma and graduated in 1985 with a Master of Science degree in Petroleum Engineering. Ms. Boone has been involved in evaluations and the estimation of reserves and resources for over 31 years. She has managed the technical reserve process at a company level for over ten years. Collectively with Ms. Boone, out internal corporate reservoir engineering group has over 100 years of experience.

Our technical team works with our banking syndicate members at least twice each year for a valuation of our reserves by the banks in our lending group and their engineers in determining the borrowing base under our revolving credit facility.

Independent Reserve Engineers

The reserves estimates for the years ended December 31, 2014 and 2013 shown herein have been independently evaluated by NSAI, a worldwide leader of petroleum property analysis for industry and financial organizations and government agencies. NSAI was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-2699. Within NSAI, the technical persons primarily responsible for auditing the estimates set forth in the NSAI audit letter incorporated herein are Mr. Dan Smith and Mr. John Hattner.  Mr. Smith, a Licensed Professional Engineer in the State of Texas (No. 49093), has been practicing consulting petroleum engineering at NSAI since 1980 and has over 7 years of prior industry experience.  He graduated from Mississippi State University in 1973 with a Bachelor of Science Degree in Petroleum Engineering.  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. He graduated from University of Miami, Florida, in 1976 with a Bachelor of Science Degree in Geology; from Florida State University in 1980 with a Master of Science Degree in Geological Oceanography; and from Saint Mary's College of California in 1989 with a Master of Business Administration Degree.  Both technical principals meet or exceed the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; both are proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines.

The proved reserves estimate for the Company for the year ended December 31, 2012 shown herein have been independently prepared by Cawley, Gillespie & Associates, Inc., which was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F‑693. Within Cawley, Gillespie & Associates, Inc., the technical person primarily responsible for preparing the estimates shown herein was Zane Meekins. Mr. Meekins has been a petroleum engineering consultant at Cawley, Gillespie & Associates, Inc. since 1989. Mr. Meekins is a Registered Professional Engineer in the State of Texas (License No. 71055) and has over 26 years of practical experience in petroleum engineering, with over 24 years of experience in the estimation and evaluation of reserves. He graduated from Texas A&M University with a BS in Petroleum Engineering. Mr. Meekins meets or exceeds 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.

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Production, Revenues and Price History

Oil and natural gas are commodities. The price that we receive for the oil and natural gas we produce is largely a function of market supply and demand. The decline in natural gas prices is being driven primarily by warmer than anticipated weather with an abundant inventory of natural gas. Oil prices drastically declined in the fourth quarter of 2014 due in part to a stronger U.S. dollar and emerging global supply and demand imbalances caused by weaker than expected demand growth and significant supply growth in North America. 

Demand is impacted by general economic conditions, public perception, weather and other seasonal conditions, including hurricanes and tropical storms. Supply is impacted by the price per barrel of oil and natural gas, service costs, global politics, and demand. Over or under supply of oil or natural gas can result in substantial price volatility. Recently, commodity prices have been volatile, and we expect that volatility to continue in the future. A substantial or extended decline in oil or natural gas prices or poor drilling results could have a material adverse effect on our financial position, results of operations, cash flows, quantities of oil and natural gas reserves that may be economically produced and our ability to access capital markets. We currently believe that we have the means necessary to fully fund our 2015 capital program in the current pricing environment. 

The following table sets forth information regarding oil and natural gas production, sales prices, and production costs for the periods indicated. For additional information on price calculations, please see information set forth in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

 

 

 

 

 

 

 

 

 

 

 

 

 

For the Years Ended December 31,

 

 

 

2014 (1)

 

2013 (1)

 

2012 (1)

 

Oil:

    

 

    

    

 

    

    

 

    

 

Total Production (MBbls)

 

 

5,618.7 

 

 

3,887.2 

 

 

2,191.0 

 

Wattenberg Field

 

 

4,486.4 

 

 

2,775.6 

 

 

1,190.8 

 

Dorcheat Macedonia Field

 

 

1,025.6 

 

 

925.2 

 

 

789.5 

 

Average sales price (per Bbl), including derivatives(2)

 

$

84.00 

 

$

88.82 

 

$

88.40 

 

Average sales price (per Bbl), excluding derivatives(2)

 

$

81.95 

 

$

91.84 

 

$

89.08 

 

Natural Gas:

 

 

 

 

 

 

 

 

 

 

Total Production (MMcf)

 

 

15,316.1 

 

 

9,975.9 

 

 

5,473.2 

 

Wattenberg Field

 

 

11,372.7 

 

 

6,269.1 

 

 

2,485.6 

 

Dorcheat Macedonia Field

 

 

4,030.6 

 

 

3,598.3 

 

 

2,973.8 

 

Average sales price (per Mcf), including derivatives(2)

 

$

5.16 

 

$

4.70 

 

$

3.76 

 

Average sales price (per Mcf), excluding derivatives(2)

 

$

5.11 

 

$

4.66 

 

$

3.62 

 

Natural Gas Liquids:

 

 

 

 

 

 

 

 

 

 

Total Production (MBbls)

 

 

260.6 

 

 

352.8 

 

 

284.7 

 

Wattenberg Field

 

 

16.8 

 

 

      10.2

 

 

      —

 

Dorcheat Macedonia Field

 

 

243.8 

 

 

342.6 

 

 

284.7 

 

Average sales price (per Bbl), including derivatives

 

$

49.14 

 

$

51.74 

 

$

55.54 

 

Average sales price (per Bbl), excluding derivatives

 

$

49.14 

 

$

51.74 

 

$

55.54 

 

Oil Equivalents:

 

 

 

 

 

 

 

 

 

 

Total Production (MBoe)

 

 

8,365.6 

 

 

5,902.7 

 

 

3,387.9 

 

Wattenberg Field

 

 

6,398.6 

 

 

3,830.7 

 

 

1,605.0 

 

Dorcheat Macedonia Field

 

 

1,874.7 

 

 

1,867.5 

 

 

1,569.8 

 

Average Daily Production (Boe/d)

 

 

22,919.3 

 

 

16,171.8 

 

 

9,257.0 

 

Wattenberg Field

 

 

17,530.5 

 

 

10,495.0 

 

 

4,385.4 

 

Dorcheat Macedonia Field

 

 

5,136.3 

 

 

5,116.4 

 

 

4,289.1 

 

Average Production Costs (per Boe)

 

$

8.44 

 

$

8.09 

 

$

9.06 

 


(1)

Amounts reflect results for continuing operations and exclude results for discontinued operations related to non‑core properties in California sold or held for sale as of December 31, 2014, 2013 and 2012.

(2)

Excludes ad valorem and severance taxes.

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Principal Customers

Three of our customers, Plains Marketing LP, Lion Oil Trading & Transportation, Inc. and High Sierra Crude Oil & Marketing comprised 29%, 19% and 11%, respectively, of our total revenue for the year ended December 31, 2014. No other single non‑affiliated customer accounted for 10% or more of oil and natural gas sales in 2014. We believe the loss of any one customer would not have a material effect on our financial position or results of operations because there are numerous potential customers of our production.

Delivery Commitments

We have entered into two purchase and transportation agreements to deliver a fixed determinable quantity of crude oil. The first agreement is anticipated to take effect during the second quarter of 2015 for 12,580 barrels per day over an initial five year term. The second agreement is anticipated to take effect during the third quarter of 2016 for 15,000 barrels per day over an initial seven year term. The aggregate financial commitment fee is approximately $540 million over the initial terms of the agreements. While the volume commitment may be met with Company volumes or third party volumes, the Company will be required to make periodic deficiency payments for any shortfalls in delivering the minimum volume commitments.

Productive Wells

The following table sets forth the number of producing oil and natural gas wells in which we owned a working interest at December 31, 2014.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Natural

 

 

 

 

 

 

 

 

 

 

 

Oil

 

Gas(1)

 

Total

 

Operated

 

 

 

Gross

 

Net

 

Gross

 

Net

 

Gross

 

Net

 

Gross

 

Net

 

Rocky Mountain

   

485 

   

408.3 

   

   

   

485 

   

408.3 

   

419 

   

396.0 

 

Mid-Continent

 

277 

 

233.7 

 

 

 

277 

 

233.7 

 

269 

 

233.4 

 

Total

 

762 

 

642 

 

 

 

762 

 

642.0 

 

688 

 

629.4 

 


(1)

All gas production is associated gas from producing oil wells.

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Acreage

The following table sets forth certain information regarding the developed and undeveloped acreage in which we own a working interest as of December 31, 2014 for each of the areas where we operate along with the PV‑10 values of each. Acreage related to royalty, overriding royalty and other similar interests is excluded from this summary.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Undeveloped

 

 

 

 

 

 

 

 

 

 

Developed Acres

 

Acres

 

Total Acres

 

 

 

 

 

 

Gross

 

Net

 

Gross

 

Net

 

Gross

 

Net

 

PV-10

 

Rocky Mountain

    

62,831 

 

53,247 

 

55,945 

 

33,703 

 

118,776 

 

86,950 

 

$

986,676 

 

Wattenberg Field

 

54,972 

 

45,388 

 

41,877 

 

24,748 

 

96,849 

 

70,136 

 

 

981,414 

 

Other Rocky Mountain

 

7,859 

 

7,859 

 

14,068 

 

8,955 

 

21,927 

 

16,814 

 

 

5,262 

 

Mid-Continent

 

6,317 

 

4,784 

 

6,250 

 

4,437 

 

12,567 

 

9,221 

 

 

353,786 

 

Dorcheat Macedonia Field

 

4,507 

 

3,114 

 

2,320 

 

1,308 

 

6,827 

 

4,422 

 

 

317,620 

 

Other Mid-Continent

 

1,810 

 

1,670 

 

3,930 

 

3,129 

 

5,740 

 

4,799 

 

 

36,166 

 

Total

 

69,148 

 

58,031 

 

62,195 

 

38,140 

 

131,343 

 

96,171 

 

$

1,340,462 

 

Undeveloped acreage

The following table sets forth the number of net undeveloped acres as of December 31, 2014 that will expire over the next three years by area unless production is established within the spacing units covering the acreage prior to the expiration dates:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Expiring 2015

 

Expiring 2016

 

Expiring 2017

 

 

 

Gross

 

Net

 

Gross

 

Net

 

Gross

 

Net

 

Rocky Mountain (1)

    

19,847 

 

13,359 

 

10,316 

 

4,525 

 

1,490 

 

856 

 

Mid-Continent

 

57 

 

43 

 

883 

 

581 

 

82 

 

20 

 

Total

 

19,904 

 

13,402 

 

11,199 

 

5,106 

 

1,572 

 

876 

 


(1)

Our 2015 budget allocates $14 million to  maintain the vast majority of our acreage within the Rocky Mountain region that is currently set to expire in 2015.

Drilling Activity

The following table describes the exploratory and development wells we drilled and completed during the years ended December 31, 2014, 2013 and 2012.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

For the Years Ended December 31,

 

 

 

2014

 

2013

 

2012

 

 

 

Gross

 

Net

 

Gross

 

Net

 

Gross

 

Net

 

Exploratory

    

    

    

    

    

    

    

    

    

    

    

    

 

Productive Wells

 

 

 

 

 

 

 

Dry Wells

 

 

 

 

 

 

 

Total Exploratory

 

 

 

 

 

 

1.0 

 

Development

 

 

 

 

 

 

 

 

 

 

 

 

 

Productive Wells

 

142 

 

124.3 

 

117 

 

102.7 

 

149 

 

140.9 

 

Dry Wells

 

 

 

 

 

 

 

Total Development

 

142 

 

124.3 

 

117 

 

102.7 

 

149 

 

140.9 

 

Total

 

142 

 

124.3 

 

118 

 

103.7 

 

150 

 

141.9 

 

 

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The following table describes the present operated drilling activities as of December 31, 2014.

 

 

 

 

 

 

 

 

 

 

 

 

As of December 31, 2014

 

 

 

Gross

 

Net

 

Exploratory

    

    

    

    

 

Rocky Mountain

 

 

 

Mid-Continent

 

 

 

Total Exploratory

 

 

 

Development

 

 

 

 

 

Rocky Mountain

 

21 

 

13.8 

 

Mid-Continent

 

 

 

Total Development

 

21 

 

13.8 

 

Total

 

21 

 

13.8 

 

Capital Expenditure Budget

Our anticipated 2015 capital budget is $420 million a decrease of approximately 37% as compared to 2014. We plan to spend approximately $380 million or 90% of our total 2015 budget in the Rocky Mountain region to drill and complete approximately 77 wells and build infrastructure in the Wattenberg Field. We plan to spend approximately $40 million in the Rocky Mountain region on non-well capital, including approximately $14 million to maintain leases and the remainder on essential infrastructure projects. In the Mid‑Continent region, we plan to spend approximately $40 million during 2015 to drill 26 gross operated wells and perform approximately 70 recompletions. The ultimate amount of capital we will expend may fluctuate materially based on, among other things, market conditions, the success of our drilling results as the year progresses and changes in the borrowing base under our revolving credit facility.

Derivative Activity

In addition to supply and demand, oil and gas prices are affected by seasonal, economic and geo‑political factors that we can neither control nor predict. We attempt to mitigate a portion of our price risk through the use of derivative contracts.

As of December 31, 2014, and through the filing date of this report, we had the following economic derivatives in place, which settle monthly:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total

 

 

 

Average

 

Average

 

 

 

Fair Market

 

 

 

 

Volumes

 

Average

 

Short Floor

 

Floor

 

Average

 

Value of

 

 

Derivative

 

(Bbls/MMBtu

 

Fixed

 

Price

 

Price

 

Ceiling

 

Asset

Settlement Period

   

Instrument

   

per day)

   

Price

   

(Short-Put)

   

(Long-Put)

   

Price

   

(Liability)

Oil

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(in thousands)

1Q 2015

 

Swap

 

6,000 

 

$

95.39 

 

 

 

 

 

 

 

 

 

 

$

22,363 

2Q 2015

 

Swap

 

5,000 

 

$

94.41 

 

 

 

 

 

 

 

 

 

 

 

17,497 

3Q 2015

 

Swap

 

2,000 

 

$

93.43 

 

 

 

 

 

 

 

 

 

 

 

6,534 

4Q 2015

 

Swap

 

2,000 

 

$

93.43 

 

 

 

 

 

 

 

 

 

 

 

6,170 

1Q 2015

 

3-Way Collar

 

6,500 

 

 

 

 

$

68.08 

 

$

84.32 

 

$

95.90 

 

 

9,264 

2Q 2015

 

3-Way Collar

 

5,500 

 

 

 

 

$

67.73 

 

$

84.09 

 

$

95.16 

 

 

7,275 

3Q 2015

 

3-Way Collar

 

6,500 

 

 

 

 

$

68.46 

 

$

84.62 

 

$

95.49 

 

 

7,846 

4Q 2015

 

3-Way Collar

 

6,500 

 

 

 

 

$

68.46 

 

$

84.62 

 

$

95.49 

 

 

7,091 

2016

 

3-Way Collar

 

5,500 

 

 

 

 

$

70.00 

 

$

85.00 

 

$

96.83 

 

 

17,765 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

$

101,805 

Gas

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

1Q 2015

 

3-Way Collar

 

15,000 

 

 

 

 

$

3.50 

 

$

4.00 

 

$

4.75 

 

$

2,200 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

$

2,200 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

$

104,005 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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The Company has hedged a significant portion of anticipated oil production in 2015 with fixed price contracts and three-way collars. Currently, forward oil prices are below the average price of our short-puts associated with our three-way collars. Should monthly crude oil settlement prices occur below the strike price of our short-puts associated with the Company’s three-way collars, we will receive a payment from our hedging counterparty equal to the difference between the strike prices of the short-put and long-put multiplied by the monthly volume associated with the three-way collar.

We do not apply hedge accounting treatment to any commodity derivative contracts. Settlements on these contracts and adjustments to fair value are shown as a component of derivative gain (loss). See Note 13—Derivatives to our consolidated financial statements for additional information regarding our derivative instruments.

Title to Properties

Our properties are subject to customary royalty interests, overriding royalty interests, obligations incident to operating agreements, liens for current taxes and other industry‑related constraints, including leasehold restrictions. We do not believe that any of these burdens materially interfere with our use of the properties in the operation of our business. We believe that we generally have satisfactory title to or rights in all of our producing properties. Generally, we undergo thorough title review and receive title opinions from legal counsel before we commence drilling operations, subject to the availability and examination of accurate title records. Although in certain cases, title to our properties is subject to interpretation of multiple conveyances, deeds, reservations, and other constraints, we believe that none of these will materially detract from the value of our properties or from our interest therein or will materially interfere with the operation of our business.

Competition

The oil and natural gas industry is highly competitive and we compete with a substantial number of other companies that have greater resources. Many of these companies explore for, produce and market oil and natural gas, carry on refining operations and market the resultant products on a worldwide basis. The primary areas in which we encounter substantial competition are in locating and acquiring desirable leasehold acreage for our drilling and development operations, locating and acquiring attractive producing oil and gas properties, attracting and retaining qualified personnel, and obtaining transportation for the oil and gas we produce in certain regions. There is also competition between producers of oil and gas and other industries producing alternative energy and fuel. Furthermore, competitive conditions may be substantially affected by various forms of energy legislation and/or regulation considered from time to time by the government of the United States; however, it is not possible to predict the nature of any such legislation or regulation that may ultimately be adopted or its effects upon our future operations. Such laws and regulations may, however, substantially increase the costs of exploring for, developing or producing gas and oil and may prevent or delay the commencement or continuation of a given operation. The effect of these risks cannot be accurately predicted.

Further, oil prices and natural gas prices do not necessarily fluctuate in direct relationship to each other. Because approximately 65% of our estimated proved reserves as of December 31, 2014 were oil and natural gas liquids reserves, our financial results are more sensitive to movements in oil prices. During the year ended December 31, 2014, the daily NYMEX WTI oil spot price ranged from a high of $107.62 per Bbl to a low of $53.27 per Bbl, and the NYMEX natural gas HH spot price ranged from a high of $6.15 per MMBtu to a low of $2.89 per MMBtu. As of the date of filing, we had commodity price derivative agreements for 2015 on approximately 60% of our anticipated production based on the mid‑point of our guidance range of 27,800 Boe/d to 30,700 Boe/d.

Insurance Matters

As is common in the oil and gas industry, we will not insure fully against all risks associated with our business either because such insurance is not available or because premium costs are considered prohibitive. A loss not fully covered by insurance could have a materially adverse effect on our financial position, results of operations or cash flows.

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Regulation of the Oil and Natural Gas Industry

Our operations are substantially affected by federal, state and local laws and regulations. In particular, oil and natural gas production and related operations are, or have been, subject to price controls, taxes and numerous other laws and regulations. All of the jurisdictions in which we own or operate properties for oil and natural gas production have statutory provisions regulating the exploration for and production of oil and natural gas, including provisions related to permits for the drilling of wells, bonding requirements to drill or operate wells, the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, sourcing and disposal of water used in the drilling and completion process, and the abandonment of wells. Our operations are also subject to various conservation laws and regulations. These include regulation of the size of drilling and spacing units or proration units, the number of wells which may be drilled in an area, and the unitization or pooling of oil and natural gas wells, and regulations that generally prohibit the venting or flaring of natural gas and that impose certain requirements regarding the ratability or fair apportionment of production from fields and individual wells.

Failure to comply with applicable laws and regulations can result in substantial penalties. Our competitors in the oil and natural gas industry are subject to the same regulatory requirements and restrictions that affect our operations. The regulatory burden on the industry increases the cost of doing business and affects profitability. Although we believe we are in substantial compliance with all applicable laws and regulations, such laws and regulations are frequently amended or reinterpreted. Therefore, we are unable to predict the future costs or impact of compliance. Additional proposals and proceedings that affect the natural gas industry are regularly considered by Congress, the states, the Federal Energy Regulatory Commission (“FERC”), and the courts. We cannot predict when or whether any such proposals or proceedings may become effective.

We believe we are in substantial compliance with currently applicable laws and regulations and that continued substantial compliance with existing requirements will not have a material adverse effect on our financial position, cash flows or results of operations. However, current regulatory requirements may change, currently unforeseen incidents may occur or past non‑compliance with laws or regulations may be discovered.

Regulation of transportation of oil

Our sales of crude oil are affected by the availability, terms and cost of transportation. Interstate transportation of oil by pipeline is regulated by FERC pursuant to the Interstate Commerce Act (“ICA”), the Energy Policy Act of 1992 and the rules and regulations promulgated under those laws. The ICA and its implementing regulations require that tariff rates for interstate service on oil pipelines, including interstate pipelines that transport crude oil and refined products (collectively referred to as “petroleum pipelines”) be just and reasonable and non‑discriminatory and that such rates and terms and conditions of service be filed with FERC.

Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations in any way that is of material difference from those of our competitors who are similarly situated.

Regulation of transportation and sales of natural gas

Historically, the transportation and sale for resale of natural gas in interstate commerce have been regulated by agencies of the U.S. federal government, primarily FERC. FERC regulates interstate natural gas transportation rates and service conditions, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas.

In the past, the federal government has regulated the prices at which natural gas could be sold. While sales by producers of natural gas can currently be made at uncontrolled market prices, Congress could reenact price controls in the future. Deregulation of wellhead natural gas sales began with the enactment of the Natural Gas Policy Act (“NGPA”) and culminated in adoption of the Natural Gas Wellhead Decontrol Act which removed controls affecting wellhead sales of natural gas effective January 1, 1993. The transportation and sale for resale of natural gas in interstate commerce is

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regulated primarily under the Natural Gas Act (“NGA”), and by regulations and orders promulgated under the NGA by FERC. In certain limited circumstances, intrastate transportation and wholesale sales of natural gas may also be affected directly or indirectly by laws enacted by Congress and by FERC regulations.

FERC issued a series of orders in 1996 and 1997 to implement its open access policies. As a result, the interstate pipelines’ traditional role as wholesalers of natural gas has been greatly reduced and replaced by a structure under which pipelines provide transportation and storage service on an open access basis to others who buy and sell natural gas. Although FERC’s orders do not directly regulate natural gas producers, they are intended to foster increased competition within all phases of the natural gas industry.

The Domenici Barton Energy Policy Act of 2005 (“EP Act of 2005”), is a comprehensive compilation of tax incentives, authorized appropriations for grants and guaranteed loans, and significant changes to the statutory policy that affects all segments of the energy industry. Among other matters, the EP Act of 2005 amends the NGA to add an anti‑market manipulation provision which makes it unlawful for any entity to engage in prohibited behavior to be prescribed by FERC. The EP Act of 2005 provides FERC with the power to assess civil penalties of up to $1,000,000 per day for violations of the NGA and increases FERC’s civil penalty authority under the NGPA from $5,000 per violation per day to $1,000,000 per violation per day. The civil penalty provisions are applicable to entities that engage in the sale of natural gas for resale in interstate commerce. On January 19, 2006, FERC issued Order No. 670, a rule implementing the anti‑market manipulation provision of the EP Act of 2005, and subsequently denied rehearing. The rules make it unlawful: (1) in connection with the purchase or sale of natural gas subject to the jurisdiction of FERC, or the purchase or sale of transportation more accessible to natural gas services subject to the jurisdiction of FERC, for any entity, directly or indirectly, to use or employ any device, scheme or artifice to defraud; (2) to make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or (3) to engage in any act or practice that operates as a fraud or deceit upon any person. The new anti‑market manipulation rule does not apply to activities that relate only to intrastate or other non‑ jurisdictional sales or gathering, but does apply to activities of gas pipelines and storage companies that provide interstate services, as well as otherwise non‑jurisdictional entities to the extent the activities are conducted “in connection with” gas sales, purchases or transportation subject to FERC jurisdiction, which now includes the annual reporting requirements under Order 704. The anti‑market manipulation rule and enhanced civil penalty authority reflect an expansion of FERC’s NGA enforcement authority.

Gathering service, which occurs upstream of jurisdictional transmission services, is regulated by the states onshore and in state waters. Although its policy is still in flux, FERC has reclassified certain jurisdictional transmission facilities as non‑jurisdictional gathering facilities, which has the tendency to increase our costs of getting gas to point of sale locations. State regulation of natural gas gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory-take requirements. Although nondiscriminatory‑take regulation has not generally been affirmatively applied by state agencies, natural gas gathering may receive greater regulatory scrutiny in the future.

Section 1(b) of the NGA exempts natural gas gathering facilities from regulation by FERC as a natural gas company under the NGA. We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to regulation as a natural gas company. However, the distinction between FERC‑ regulated transmission services and federally unregulated gathering services is the subject of ongoing litigation, so the classification and regulation of our gathering facilities are subject to change based on future determinations by FERC, the courts or Congress.

Our sales of natural gas are also subject to requirements under the Commodity Exchange Act (“CEA”), and regulations promulgated thereunder by the Commodity Futures Trading Commission (“CFTC”). The CEA prohibits any person from manipulating or attempting to manipulate the price of any commodity in interstate commerce or futures on such commodity. The CEA also prohibits knowingly delivering or causing to be delivered false or misleading or knowingly inaccurate reports concerning market information or conditions that affect or tend to affect the price of a commodity.

Intrastate natural gas transportation is also subject to regulation by state regulatory agencies. The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Insofar as such regulation within a particular state will

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generally affect all intrastate natural gas shippers within the state on a comparable basis, we believe that the regulation of similarly situated intrastate natural gas transportation in any states in which we operate and ship natural gas on an intrastate basis will not affect our operations in any way that is of material difference from those of our competitors. Like the regulation of interstate transportation rates, the regulation of intrastate transportation rates affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas.

Changes in law and to FERC policies and regulations may adversely affect the availability and reliability of firm and/or interruptible transportation service on interstate pipelines, and we cannot predict what future action FERC will take. We do not believe, however, that any regulatory changes will affect us in a way that materially differs from the way they will affect other natural gas producers, gatherers and marketers with which we compete.

Regulation of production

The production of oil and natural gas is subject to regulation under a wide range of local, state and federal statutes, rules, orders and regulations. Federal, state and local statutes and regulations require permits for drilling operations, drilling bonds and reports concerning operations. The states in which we own and operate properties have regulations governing conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum allowable rates of production from oil and natural gas wells, the regulation of well spacing, and plugging and abandonment of wells. The effect of these regulations is to limit the amount of oil and natural gas that we can produce from our wells and to limit the number of wells or the locations at which we can drill, although we can apply for exceptions to such regulations or to have reductions in well spacing. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction.

We own interests in properties located onshore in two U.S. states. These states regulate drilling and operating activities by requiring, among other things, permits for the drilling of wells, maintaining bonding requirements in order to drill or operate wells, and regulating the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled and the plugging and abandonment of wells. The laws of these states also govern a number of environmental and conservation matters, including the handling and disposing or discharge of waste materials, the size of drilling and spacing units or proration units and the density of wells that may be drilled, unitization and pooling of oil and gas properties and establishment of maximum rates of production from oil and gas wells. Some states have the power to prorate production to the market demand for oil and gas.

Regulation of derivatives and reporting of government payments

The Dodd‑Frank Wall Street Reform and Consumer Protection Act (the “Dodd‑Frank Act”) was passed by Congress and signed into law in July 2010. The Dodd‑Frank Act is designed to provide a comprehensive framework for the regulation of the over‑the‑counter derivatives market with the intent to provide greater transparency and reduction of risk between counterparties. The Dodd‑Frank Act subjects swap dealers and major swap participants to capital and margin requirements and requires many derivative transactions to be cleared on exchanges. The Dodd‑Frank Act provides for a potential exemption from these clearing and cash collateral requirements for commercial end‑users. In addition, in August 2012, the SEC issued a final rule under Section 1504 of the Dodd‑Frank Act, Disclosure of Payment by Resource Extraction Issuers, which would have required resource extraction issuers, such as us, to file annual reports that provide information about the type and total amount of payments made for each project related to the commercial development of oil, natural gas, or minerals to each foreign government and the federal government. In July 2014, the U.S. District Court for the District of Columbia vacated the rule, and the SEC has announced it will not appeal the court’s decision. However, the SEC may propose revised resource extraction payments disclosure rules applicable to our business.

Environmental, Health and Safety Regulation

Our natural gas and oil exploration and production operations are subject to numerous stringent federal, regional, state and local statutes and regulations governing safety and health, the discharge of materials into the environmental or otherwise relating to environmental protection, some of which carry substantial administrative, civil

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and criminal penalties for failure to comply. These laws and regulations may require the acquisition of permits before drilling or other regulated activity commences; restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling, production and transporting through pipelines; govern the sourcing and disposal of water used in the drilling and completion process; limit or prohibit drilling activities in certain areas and on certain lands lying within wilderness, wetlands, frontier and other protected areas; require some form of remedial action to prevent or mitigate pollution from former operations such as plugging abandoned wells or closing earthen pits; establish specific safety and health criteria addressing worker protection and impose substantial liabilities for pollution resulting from operations or failure to comply with regulatory filings. In addition, these laws and regulations may restrict the rate of production.

The following is a summary of the more significant existing environmental and health and safety laws and regulations to which our business operations are subject and for which compliance may have a material adverse impact on our capital expenditures, results of operations or financial position.

Hazardous substances and waste handling

The Comprehensive Environmental Response, Compensation and Liability Act of 1980 (“CERCLA”), also known as the Superfund law, and comparable state laws impose liability without regard to fault or the legality of the original conduct on certain classes of persons who are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include current and prior owners or operators of the site where the release occurred and entities that disposed or arranged for the disposal of the hazardous substances found at the site. Under CERCLA, these potentially “responsible persons” may be subject to strict, joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources, and for the costs of certain health studies, and it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. We are able to control directly the operation of only those wells with respect to which we act as operator. Notwithstanding our lack of direct control over wells operated by others, the failure of an operator other than us to comply with applicable environmental regulations may, in certain circumstances, be attributed to us. We generate materials in the course of our operations that may be regulated as hazardous substances but we are not aware of any liabilities for which we may be held responsible that would materially and adversely affect us.

The Resource Conservation and Recovery Act (“RCRA”), and analogous state laws, impose requirements on the generation, handling, storage, treatment and disposal of nonhazardous and hazardous solid wastes. RCRA specifically excludes certain drilling fluids, produced waters, and other wastes associated with the exploration, development, or production of crude oil, natural gas or geothermal energy from regulation as hazardous wastes. However, these wastes may be regulated by the EPA or state agencies under RCRA’s less stringent nonhazardous solid waste provisions, state laws or other federal laws. Moreover, it is possible that these particular oil and natural gas exploration, development and production wastes now classified as nonhazardous solid wastes could be classified as hazardous wastes in the future. A loss of the RCRA exclusion for drilling fluids, produced waters and related wastes could result in an increase in our costs to manage and dispose of generated wastes, which could have a material adverse effect on our results of operations and financial position. In addition, in the course of our operations, we generate some amounts of ordinary industrial wastes, such as paint wastes, waste solvents, laboratory wastes and waste compressor oils that are regulated as hazardous wastes. Although the costs of managing hazardous waste may be significant, we do not believe that our costs in this regard are materially more burdensome than those for similarly situated companies.

We currently own or lease, and have in the past owned or leased, properties that have been used for numerous years to explore and produce oil and natural gas. Although we have utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons and wastes may have been disposed of or released on or under the properties owned or leased by us or on or under the other locations where these hydrocarbons and wastes have been taken for treatment or disposal. In addition, certain of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons and wastes were not under our control. These properties and wastes disposed thereon may be subject to CERCLA, RCRA and analogous state laws. Under these laws, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), to clean up contaminated property (including groundwater contaminated by prior owners or operators), to pay

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for damages for the loss or impairment of natural resources, and to take measures to prevent future contamination from our operations.

Pipeline safety and maintenance

Pipelines, gathering systems and terminal operations are subject to increasingly strict safety laws and regulations. Both the transportation and storage of refined products and crude oil involve a risk that hazardous liquids may be released into the environment, potentially causing harm to the public or the environment. In turn, such incidents may result in substantial expenditures for response actions, significant government penalties, liability to government agencies for natural resources damages, and significant business interruption. The U.S. Department of Transportation has adopted safety regulations with respect to the design, construction, operation, maintenance, inspection and management of our pipeline and storage facilities. These regulations contain requirements for the development and implementation of pipeline integrity management programs, which include the inspection and testing of pipelines and the correction of anomalies. These regulations also require that pipeline operation and maintenance personnel meet certain qualifications and that pipeline operators develop comprehensive spill response plans.

There have been recent initiatives to strengthen and expand pipeline safety regulations and to increase penalties for violations. The Pipeline Safety, Regulatory Certainty, and Job Creation Act was signed into law in early 2012. In addition, the Pipeline and Hazardous Materials Safety Administration has issued new rules to strengthen federal pipeline safety enforcement programs.

Air emissions

The Clean Air Act (“CAA”) and comparable state laws and regulations restrict the emission of air pollutants from many sources, including oil and gas operations, and impose various monitoring and reporting requirements. These laws and regulations may require us to obtain pre‑approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and comply with stringent air permit requirements or utilize specific equipment or technologies to control emissions. Obtaining required air permits can significantly delay the development of certain oil and natural gas projects. Over the next several years, we may be required to incur certain capital expenditures for air pollution control equipment or other air emissions related issues.

For example, on August 16, 2012, the EPA published final rules under the CAA that subject oil and natural gas production, processing, transmission and storage operations to regulation under the New Source Performance Standards and National Emission Standards for Hazardous Air Pollutants programs. With regards to production activities, these final rules require, among other things, the reduction of volatile organic compound emissions from three subcategories of fractured and refractured gas wells for which well completion operations are conducted: wildcat (exploratory) and delineation gas wells; low reservoir pressure non‑wildcat and non‑delineation gas wells; and all “other” fractured and refractured gas wells. All three subcategories of wells must route flow back emissions to a gathering line or be captured and combusted using a combustion device such as a flare after October 15, 2012. However, the “other” wells must use reduced emission completions, also known as “green completions,” with or without combustion devices, after January 1, 2015. These regulations also establish specific new requirements regarding emissions from production‑related wet seal and reciprocating compressors effective October 15, 2012 and from pneumatic controllers and storage vessels, effective October 15, 2014. The EPA received numerous requests for reconsideration of these rules from both industry and the environmental community, and court challenges to the rules were also filed. The EPA issued revised rules in 2013 and 2014 in response to some of these requests. Specifically, on September 23, 2013, the EPA published a final amendment extending the compliance dates for certain groups of storage vessels to April 15, 2014 and April 15, 2015, and on December 31, 2014, the EPA issued a final amendment clarifying certain reduced emission completion requirements.

On December 17, 2014, the United States Environmental Protection Agency (the ‘‘EPA’’) proposed to revise and lower the existing 75 ppb national ambient air quality standard (‘‘NAAQS’’) for ozone under the federal Clean Air Act to a range within 65-70 ppb. The EPA is also taking public comment on whether the ozone NAAQS should be revised as low as 60 ppb. A lowered ozone NAAQS in a range of 60-70 ppb could result in a significant expansion of ozone nonattainment areas across the United States, including areas in which we operate. Oil and natural gas operations in ozone nonattainment areas would likely be subject to increased regulatory burdens in the form of more stringent emission controls, emission offset requirements, and increased permitting delays and costs. In addition, in February

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2014, the Colorado Department of Public Health and Environment’s Air Quality Control Commission (“AQCC”) adopted new and revised air quality regulations that impose stringent new requirements to control emissions from existing and new oil and gas facilities in Colorado. The proposed regulations include new control, monitoring, recordkeeping, and reporting requirements on oil and gas operators in Colorado. For example, the new regulations impose Storage Tank Emission Management (“STEM”) requirements for certain new and existing storage tanks. The STEM requirements require us to install costly emission control technologies as well as monitoring and recordkeeping programs at most of our new and existing well production facilities. The new Colorado regulations also impose a Leak Detection and Repair (“LDAR”) program for well production facilities and com