UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

Form 10-K

 

 

 

For the fiscal year ended December 31, 2015

OR

 

For the transition period from              to             

Commission file number: 333-134748

 

Chaparral Energy, Inc.

(Exact name of registrant as specified in its charter)

 

(405) 478-8770

(Registrant’s telephone number, including area code)

 

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

None.

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

None.

 

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

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

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  o     No  x

(Explanatory Note: The registrant is a voluntary filer and is not subject to the filing requirements of the Securities Exchange Act of 1934.)

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

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

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

 

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

The aggregate market value of common equity held by non-affiliates of the registrant is not determinable as such shares are privately held and there is no public market for such shares.

Number of shares outstanding of each of the issuer’s classes of common stock as of March 25, 2016:  

 

 

 

 

 

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CHAPARRAL ENERGY, INC.

Index to Form 10-K

 

 

 

 

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CAUTIONARY NOTE

REGARDING FORWARD-LOOKING STATEMENTS

This report includes statements that constitute forward-looking statements within the meaning of the federal securities laws. These statements are subject to risks and uncertainties. These statements may relate to, but are not limited to, information or assumptions about us, our capital and other expenditures, dividends, financing plans, capital structure, cash flow, pending legal and regulatory proceedings and claims, including environmental matters, future economic performance, operating income, cost savings, and management’s plans, strategies, goals and objectives for future operations and growth. These forward-looking statements generally are accompanied by words such as “intend,” “anticipate,” “believe,” “estimate,” “expect,” “should,” “seek,” “project,” “plan” or similar expressions. Any statement that is not a historical fact is a forward-looking statement. It should be understood that these forward-looking statements are necessarily estimates reflecting the best judgment of senior management, not guarantees of future performance. They are subject to a number of assumptions, risks and uncertainties that could cause actual results to differ materially from those expressed or implied in the forward-looking statements. Forward-looking statements in this report may include, for example, statements about:

These forward-looking statements represent intentions, plans, expectations, assumptions and beliefs about future events and are subject to risks, uncertainties and other factors. Many of those factors are outside of our control and could cause actual results to differ materially from the results expressed or implied by those forward-looking statements. In addition to the risk factors described under the heading “Risk Factors,” the factors include:

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Should one or more of these risks or uncertainties materialize, or should any of our assumptions prove incorrect, actual results may vary in material respects from those projected in the forward-looking statements contained herein. We undertake no obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise, except as may be required under applicable securities laws. All forward-looking statements included herein are expressly qualified in their entirety by the cautionary statements contained or referred to in this section.

 

 

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GLOSSARY OF TERMS

The terms defined in this section are used throughout this annual report on Form 10-K:

 

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PART I

Unless the context requires otherwise, references in this annual report to the “Company,” “Chaparral,” “we,” “our” and “us” refer to Chaparral Energy, Inc. and its subsidiaries on a consolidated basis. We have provided definitions of terms commonly used in the oil and natural gas industry in the “Glossary of Terms” at the beginning of this annual report.

ITEMS 1. AND 2. BUSINESS AND PROPERTIES

Overview

Founded in 1988, we are a Delaware corporation headquartered in Oklahoma City and a pure play Mid-Continent independent oil and natural gas exploration and production company. We have capitalized on our sustained success in the Mid-Continent area in recent years by expanding our holdings to become a leading player in the liquids rich STACK play, which is home to multiple oil-rich reservoirs including the Oswego, Meramec, Osage, Woodford and Hunton formations. In addition, we have significant holdings in the Mississippi Lime play and a leadership position in CO₂ EOR where we are now the third largest CO₂ EOR operator in the United States based on the number of active projects. This EOR position is underscored by our activity in the North Burbank Unit in Osage County, Oklahoma, which is the single largest oil recovery unit in the state.

During 2015, our average net daily production was 27.9 MBoe and our oil and natural gas revenues were $324.3 million. As of December 31, 2015, we had estimated proved reserves of 155.5 MMBoe with a PV-10 value of approximately $731 million and an estimated reserve life of approximately 15.2 years. These estimated proved reserves included 84.8 MMBoe of reserves in our active EOR Project Areas. Our reserves were 46% proved developed, 73% crude oil, and 8% natural gas liquids. We set forth our definition of PV-10 value (a non-GAAP measure) and a reconciliation of the standardized measure of discounted future net cash flows to PV-10 value below under “Non-GAAP Financial Measures and Reconciliations.”

Beginning in 2011, we increased our focus on acquisitions of leasehold acreage and exploration in resource plays with repeatable drilling opportunities. Our focus has been concentrated in the Mid-Continent region, with most of our recent capital dollars being spent in the STACK play. By concentrating in this core area, we are developing a significant resource base to achieve future production and reserve growth.

Outlook

The upstream oil and gas business is cyclical and we are currently operating in a sustained lower commodity price environment. The commodity price decline that began in mid-2014 has continued its declining trajectory into 2016, with the price per barrel of West Texas Intermediate (“WTI”) oil falling below $30 on several occasions. The depressed pricing environment has continued for longer than expected. Our average realized prices for 2015 decreased 49% for crude oil, 42% for natural gas and 57% for NGLs as compared with 2014. These low prices resulted in a reduction in our capital spending program, had significant negative impacts on our revenues, profitability, cash flows, liquidity and proved reserves, resulted in asset impairments and caused us to reduce our workforce. At current prices, we also expect the next borrowing base redetermination of our Credit Facility to result in a borrowing base that is significantly less than the amount outstanding, which will result in a deficiency.

Significant factors that will affect 2016 commodity prices include: the impact of announced capital spending decreases on forecasted United States oil, NGL and gas supplies; the ongoing effect of economic stimulus initiatives; fiscal challenges facing the United States federal government and potential changes to the tax laws in the United States; continuing economic struggles in European and Asian nations; political and economic developments in North Africa and the Middle East; demand from Asian and European markets; the extent to which members of OPEC and other oil exporting nations are willing or able to manage oil supply through export quotas; the supply and demand fundamentals for NGLs in the United States and the pace at which export capacity grows; and overall North American gas supply and demand fundamentals, including gas storage levels.

Business Strategy

Given the uncertainty regarding the timing and magnitude of an eventual recovery of crude oil prices, we have adapted our near-term business strategy to focus on improving our liquidity, reducing operating costs and efficiently executing our limited capital program. Our near term strategy will focus on:

Restructuring our debt to preserve liquidity and financial strength. Lower commodity prices have negatively impacted revenues, earnings and cash flows, and sustained low oil and natural gas prices are having a material and adverse effect on our liquidity. As a result of these adverse consequences, we may not have sufficient liquidity to meet our anticipated working capital, debt service and other liquidity needs, in particular those pertaining to any acceleration of indebtedness within the next 12 months. We are

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currently pursuing or considering a number of actions to actively address our liquidity issues and high leverage levels. These alternatives include (i) debt- for-debt exchanges or debt-for-equity exchanges, (ii) potentially seeking relief under Chapter 11 of the U.S. Bankruptcy Code, (iii) obtaining waivers or amendments from our lenders, (iv) minimizing our planned capital investment,  (v) effectively managing our working capital, (vi) improving our cash flows from operations and (vii) dispositions of non-core assets. Our liquidity is discussed in further detail within “Liquidity and Capital Resources” in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Allocating our reduced capital investment to our higher return play acreage. We have reduced planned capital investments in 2016 to $110.6 million, approximately half of our 2015 capital spending. We have allocated $63.7 million, or 58% of our 2016 capital budget, to our E&P Areas of which $50.7 million of the expenditure will be on drilling and completion activities. While we commenced the year with three drilling rigs, we have reduced down to one drilling rig as of March 2016 which we expect to continue drilling in our higher return STACK play through the third quarter of 2016. We have allocated $44.8 million, or 41% of our 2016 capital budget, for development of our EOR projects in 2016, which includes expanding a limited number of CO₂ flood patterns in our North Burbank Unit, infrastructure, continued CO₂ purchases and maintenance.

Maximize cost savings and efficiency gains. We are preserving the significant reductions in our drilling and completions costs, lease operating expenses and general and administrative expenses achieved during 2015 and are aggressively pursuing further cost reductions in 2016. Our current cost reduction efforts are focused on targeting further price concessions from third party vendors, specifically those involved in our drilling and completion activities and day-to-day well maintenance. We are also monitoring the size of our workforce to ensure that we are appropriately staffed during the current downturn.

Upon returning to a normalized commodity price environment, our business strategies would return to strategies substantially similar to those that we have pursued over the last several years, which include delivering shareholder value through consistent growth of cash flow, production and reserves. Key components of our long-term business strategy include:  

 2015 Highlights

The following are material events with respect to our operations that have impacted our liquidity or results of operations, and/or are expected to impact these items in future periods:

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Properties

The following table presents our proved reserves as of December 31, 2015, and average net daily production for both the year ended and quarter ended December 31, 2015, by our areas of operation. Reserves were estimated using a twelve-month average price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the twelve-month period prior to the end of the reporting period, unless prices were defined by contractual arrangements. Prices used as of December 31, 2015, before the effect of differentials, were $50.28 per Bbl of oil, $2.58 per Mcf of natural gas and $15.84 per Bbl of natural gas liquids.

 

E&P Areas

We have recently realigned the plays within our E&P Areas to better highlight those areas where we are focusing our operations and where our current and future capital will be spent. E&P Areas currently include the following plays: the STACK, Mississippi Lime, Panhandle Marmaton and Legacy Production Areas. During 2015, capital expenditures on drilling in the STACK and Mississippi Lime plays accounted for 55% and 35%, respectively of our drilling expenditures. E&P Areas also includes our Legacy Production Areas which primarily include mature properties with low production decline curves and non-core properties that we have disposed (see “Note 4—Acquisitions and divestitures” in Item 8. Financial Statements and Supplementary Data). Presently, the majority of properties in our Legacy Production Areas are located in the Mid-Continent and are held by production.

STACK Play. The STACK is an acronym for Sooner Trend Anadarko Canadian Kingfisher which is indicative of a play area in the Anadarko Basin of Oklahoma in which we operate. It is a horizontal drilling play in an area of previously drilled vertical wells

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with multiple productive reservoirs. It encompasses all or parts of Blaine, Canadian, Garfield, Kingfisher and Major counties in Oklahoma. Our STACK play’s borders include the Nemaha Ridge (East), the Chester outcrop (North), and deep gas bearing characteristics (South and West). This thick column (500’+) includes multiple, stacked, and productive reservoirs, each with high oil saturations and include the Woodford, Osage, Meramec, Oswego, and other intervals within the STACK area. The organic-rich Woodford Shale is the primary source of hydrocarbon migration into and present in the target reservoirs, which act as natural conduits for the oil migration from the Woodford. These complex carbonate-silt-shale stratigraphic intervals have proven to be very conducive to horizontal drilling and completion techniques. We currently own approximately 219,000 (110,000 net) surface acres in this play.

Primarily as a result of our drilling activity, our average net daily production from this area was 4,458 Boe/d in 2015 compared to 3,542 Boe/d in 2014 and 464 Boe/d in 2013. During 2015, we spent $62.9 million on drilling activities in our STACK play, compared to a budget of $57.2 million, where we drilled and/or participated in the drilling of 34 (16 net) horizontal wells. Our drilling opportunities across the different intervals of the STACK are described below where acreage is duplicated for the stacked play position.

STACK – Meramec. We currently own approximately 84,000 (36,000 net) acres targeting the Meramec interval within our STACK play. Within this area, our drilling locations are in Kingfisher county (“North Meramec”) and Canadian county (“South Meramec”). For a typical well in the North Meramec, we estimate the anticipated ultimate recovery per well to be 354 MBoe, of which 53% is prospective for oil, at an estimated completed well cost of approximately $3.0 million. For a typical well in the South Meramec, we estimate the anticipated ultimate recovery per well to be 434 MBoe, of which 67% is prospective for oil, at an estimated completed well cost of approximately $4.0 million.

STACK – Osage. We currently own approximately 183,000 (107,500 net) acres targeting the Osage interval within our STACK play primarily located in Garfield, Kingfisher and Major counties. Within this area, our drilling locations are primarily in Garfield and Kingfisher counties. For a typical well in Kingfisher county, we estimate the anticipated ultimate recovery per well to be 315 MBoe, of which 52% is prospective for oil, at an estimated completed well cost of approximately $3.0 million. For a typical well in Garfield county, we estimate the anticipated ultimate recovery per well to be 434 MBoe, of which 30-60% are liquids, at an estimated completed well cost of approximately $3.1 million.

STACK – Oswego. We currently own approximately 117,000 (87,000 net) acres targeting the Oswego interval within our STACK play. Within this area, our drilling locations are primarily in Kingfisher and Garfield counties. Our primary Oswego drilling focus is in Kingfisher county where we estimate a typical well’s anticipated ultimate recovery to be 351 MBoe, of which 94% is prospective for oil, at an estimated completed well cost of approximately $2.7 million.

STACK – Woodford. We currently own approximately 162,000 (84,000 net) acres targeting the Woodford interval within our STACK play. Within this area, our drilling locations are primarily located within Canadian and Garfield counties. Our primary Woodford drilling focus is in Canadian county where we estimate a typical well’s anticipated ultimate recovery to be 443 MBoe, of which 59% is prospective for oil, at an estimated completed well cost of approximately $4.5 million.

Mississippi Lime Play – Various Counties, Oklahoma. The Mississippi Lime, located in North-Central Oklahoma, is a shallow carbonate play (mostly Limestone) with depths ranging from 5,000 feet to 6,000 feet. Our Mississippi Lime play is not a new play, but is now a horizontal development among and bordering on legacy vertical producing fields. This area has a long history of production from vertical wells and a well-developed infrastructure system to support further development. Our operations in our Mississippi Lime play are focused in the northwest region of Oklahoma and currently consist of 71,000 (50,000 net) acres. Across the play, we estimate the anticipated ultimate recovery per well to be 376 MBoe, of which 46% is prospective for oil, at an estimated completed well cost of $2.5 million.

Primarily as a result of our drilling activity, our average net daily production from this area was 5,811 Boe/d in 2015 compared to 5,367 Boe/d in 2014 and 3,416 Boe/d in 2013. During 2015, we spent $40.5 million on drilling activities in the play. We drilled and/or participated in the drilling of 26 (13 net) horizontal wells that were completed during 2015. As we align our 2016 drilling capital budget expenditures and focus on the plays that provide the highest returns, this area will be allocated materially less capital in 2016.

Panhandle Marmaton Play – Texas and Oklahoma Panhandles. Our Panhandle Marmaton play development program began in 2012. Our leasehold position provides for horizontal drilling opportunities targeting the Marmaton lime, which consists of numerous productive carbonate benches. We currently own approximately 126,000 (86,500 net) acres in this play. As a result of decreased capital spending in this area, our net average daily production from this area was approximately 1,645 Boe/d in 2015 compared to 2,878 Boe/d and 889 Boe/d in 2014 and 2013, respectively. We did not incur significant capital expenditure in this play in 2015 and have not budgeted any significant capital expenditures in this play for 2016.

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Legacy Production Areas. Our Legacy Production Areas primarily include mature producing properties with low production decline curves and includes most of our vertical production and our horizontal production outside of the STACK and Mississippi Lime including formations of the Cleveland Sand and, Granite Wash. For prior year comparative purposes, these areas also include our Ark-La-Tex, Permian Basin, and North Texas properties which we divested in 2014. The production volumes from the divested properties are reflected in production volumes for the prior year period. We did not incur significant capital expenditure in these areas in 2015 and have not budgeted any significant capital expenditures for 2016.

In an effort to curb a recent increase in seismic activity, the Oklahoma Corporation Commission (the “OCC”) issued a directive on February 16 to operators of salt water disposal wells in northwestern Oklahoma to reduce injection volumes by approximately 40% from 2015 levels. This area of interest encompasses our Mississippi Lime play. Due to proactive measures taken by us in 2015 and normal production decline, we do not anticipate this directive to impact production of our operated wells as our injected volumes are currently below limits imposed by the directive. Although the directive may impact production from our non-operated wells, we do not expect any impact to be significant. On March 7, in a second directive, the OCC expanded its salt water volume reduction directive to include areas in central Oklahoma, which encompasses our STACK play. We are currently evaluating the impact of the second OCC directive on our operations but do not anticipate any significant impact. Please see “Studies by both state or federal agencies demonstrating a correlation between earthquakes and oil and natural gas activities could result in increased regulatory and operational burdens” in  Item 1A. Risk Factors of this report for a further discussion of the OCC seismic-related directives.

During 2015, we incurred $25.9 million in capital expenditures on acquisitions which were comprised primarily of leasehold acreage in Kingfisher, Canadian and Garfield counties in Oklahoma, which are prospective for drilling in our STACK play.

EOR Project Areas

Our EOR Project Areas include both our active EOR projects and potential EOR projects, as reflected in the following table:

 

 

We have been actively implementing and managing CO₂ EOR in the Panhandle and Central Oklahoma areas since 2001. We now have CO₂ supply agreements in place in the Burbank, Panhandle, and Central Oklahoma areas, and we have built CO₂ pipelines to reach several of our field locations in each of these areas.

The U.S. Department of Energy–Office of Fossil Energy published reports in February 2006 estimating that significant oil reserves could be economically recovered in Oklahoma and Texas through CO₂ EOR processes. With our infrastructure, we believe that we will be well positioned to participate in the exploitation of those reserves. CO₂ miscible flooding is implemented and managed as a closed system consisting of the reservoir and surface piping. The physical material balance of the system means that the CO₂ is produced and recycled many times once it has been injected. Combined with the incoming purchased CO₂ supply, the recycled CO₂ supply allows us to systematically develop additional flood patterns in contiguous acreage to the active patterns, or to expand into new projects. If larger volumes of CO₂ become available, projects could be developed on accelerated timelines, while a more limited supply dictates a prolonged expansion. Due to the size of our EOR projects, the fixed rate of CO₂ availability which is secured for the long-term period, and the limitation of third party services, we expect the development of our EOR projects will extend beyond five years in many cases. Our significant active EOR projects are discussed below.

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The following table presents proved reserves, production, number of wells and average working interest related to our major EOR property areas:

 

North Burbank Unit. As of December 31, 2015, our North Burbank Unit, which is our largest property and for which we are the operator, accounted for 50%, of our total proved reserves and 92% of our active EOR projects proved reserves. The producing zones are the Red Fork and Bartlesville formations and occur at a depth of approximately 3,000 feet. Our average net daily production from this Unit increased from 2014 to 2015 as a result of our CO₂ injection and the associated response. Due to the size of our North Burbank Unit, there is insufficient CO₂ availability and third party services available to complete the development of our North Burbank Unit within five years, and as a result the development of our North Burbank Unit will be an ongoing project.

We commenced CO₂ injection at our North Burbank Unit in June 2013. The CO₂ utilized at this location is sourced from an existing nitrogen fertilizer plant in Coffeyville, Kansas as described further below and in “Note 14—Commitments and contingencies” in Item 8. Financial Statements and Supplementary Data of this report. In 2013, we completed the Coffeyville CO₂ compression facility and a 68-mile pipeline to transport the CO₂ to the Burbank field. We began CO₂ injection at our North Burbank Unit in June 2013. With some response by December, we added proved CO₂ EOR reserves of 5.3 MMBoe and removed polymer reserves of 1.5 MMBoe for our North Burbank Unit in late 2013. We continued CO₂ injection within Phase I and expanded into Phase II of the CO₂ flood during 2014. With additional response in 2014, we added proved CO₂ EOR reserves of 25.2 MMBoe and removed the remainder of our polymer reserves of 12.6 MMBoe. Given our record of proven response, in 2015 we added 36.4 MMBoe of proved CO₂ EOR reserves related to all remaining phases at the unit during the third quarter of 2015. Development of remaining phases will follow in future years as a sufficient volume of purchased and recycled CO₂ becomes available.

Our total investment in our North Burbank Unit during 2015 was $31.7 million compared to an annual budget of $23.1 million,  associated with upgrading and installing surface facilities, standard well maintenance and improvements, and purchasing CO₂ for injection. Our budgeted capital expenditure in 2016, for which we have allocated $26.4 million, will be utilized to continue developing our North Burbank Unit, primarily for infrastructure build out, development of a limited number of additional patterns, continuing CO₂ injection and field maintenance. Significant additional capital expenditures will be required over multiple years to fully develop the North Burbank Unit.

Camrick Area Units. Our Camrick Area Units consist of our Camrick Unit, where we began CO₂ injection in 2001 and our North Perryton Unit, where we began CO₂ injection in 2006. Currently, CO₂ injection operations are continuing in the Phase I, II and III areas of our Camrick Unit and within our North Perryton Unit.

Our investment in our Camrick Area Units during 2015 was $3.6 million, compared to an annual budget of $4.4 million, associated with the continued purchase of CO₂, infrastructure and remedial well work.

Booker Area Units.  All of the reserves in this Unit are considered EOR. In September 2009, we began CO₂ injection into our three Booker Area Units. We have been able to maintain production levels by continuously optimizing wells and facilities, mitigating failures, and reducing overall downtime.

Our total investment in our Booker Area Units during 2015 was $4.3 million, which was equal to our annual budget, for continued purchase of CO2, installation of a variable frequency drive for the original recycle compressor, installation of a gas fired recycle compressor and standard well maintenance.

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Farnsworth Unit. Our Farnsworth Unit, of which all of the reserves in this Unit are considered EOR reserves, lies to the south of and is analogous to the Camrick Area Units. We acquired a 100% working interest in our Farnsworth Unit in November 2009 and we began CO₂ injection in December 2010. The increase in average net daily production from 2014 to 2015 is primarily due to CO₂ response and minimal downtime. During 2015, we invested $9.6 million compared to an annual budget of $7.6 million, for continued purchase of CO₂, standard well maintenance and battery upgrades. We expect our budgeted capital expenditures for 2016 in this area to be lower than our 2015 expenditures.

Potential EOR Properties. We define these properties primarily as properties that we have assessed as having commercial EOR potential and that we plan to develop once additional CO₂ volumes become available. We have not allocated any significant amount of our 2015 or 2016 capital budget to this area.

CO₂ Sources and Pipelines

We capture, compress and transport CO₂ to our active EOR projects from four separate CO₂ sources.

Coffeyville. Our CO₂ source for our North Burbank Unit is located in Coffeyville, Kansas. In March 2011, we signed a 20-year contract with renewal options to purchase up to 100% of CO₂ emissions from the Coffeyville nitrogen fertilizer plant. The fertilizer plant reserves the right to install additional equipment and use some of the CO₂ to make certain fertilizer products, which could reduce our CO₂ purchases. We own and operate the Coffeyville CO₂ compression facility on land leased from the owner of the fertilizer plant, and 68 miles of CO₂ pipeline to transport the CO₂ to the Burbank field, both of which we completed in 2013. During 2015, we purchased an average of 26 MMcf/d from this source. By securing this contract and completing the compression facility and pipeline, we can provide CO₂ to our North Burbank Unit on an acceptable runtime basis and at a reasonably predictable cost, and establish the platform to expand our CO₂ recovery operations in our North Burbank Unit.

Borger. We have a long-term contract to purchase up to approximately 20 MMcf/d of CO₂ produced at the Agrium nitrogen fertilizer plant in Borger, Texas. The fertilizer plant reserves the right to install additional equipment and use some of the CO₂ to make certain fertilizer products, and has commenced installation of such additional equipment in 2014. We own and operate the Borger CO₂ compression facility on land leased from Agrium, and 80 miles of CO₂ pipelines to deliver the Borger-sourced CO₂ to our active EOR units in our Camrick Area and Farnsworth Units. During 2015 we purchased an average of 11 MMcf/d from this source. The Agrium fertilizer plant is currently undergoing a modification to allow additional fertilizer production. As a result of this modification, we expect our CO2 volumes to be reduced in early 2017.  If the available CO2 volume decreases below 5 MMcf/d, we likely will not be able to operate the compression facility.  Unless modified or replaced, the CO2 purchase contract expires in 2021.

Arkalon. We have a long-term contract to purchase up to approximately 15 MMcf/d of CO₂ produced at the Arkalon ethanol plant near Liberal, Kansas. We own and operate the Arkalon CO₂ compression and processing facility on land leased from Arkalon, as well as the 91 miles of CO₂ pipeline to deliver the Arkalon-sourced CO₂ to our active EOR units in our Booker Area and Farnsworth Units. During 2015 we purchased an average of 10 MMcf/d from this source.

Enid. We have a contract to purchase up to approximately 10 MMcf/d of CO₂ produced at the Koch nitrogen fertilizer plant in Enid, Oklahoma. The fertilizer plant reserves the right to install additional equipment and use some of the CO₂ to make certain fertilizer products, which could reduce our CO₂ purchases. We own a partial interest in the Enid CO₂ compression facility and 142 miles of CO₂ pipeline, which deliver the Enid-sourced CO₂ to our active EOR project in southern Oklahoma. During 2015 we purchased an average of approximately one MMcf/d from this Enid CO₂ source. Unless modified or replaced, both the CO₂ purchase contract and the operations agreement for the compression facility and pipeline expire in 2016.

Our total investment for CO₂ purchases and CO₂ pipeline and compression facility infrastructure during 2015 was $21.7 million. We have allocated approximately $25.6 million of our capital expenditures budget for 2016 to CO₂ purchases as well as maintenance associated with our CO₂ pipeline and compression facility infrastructure.

Oil and Natural Gas Reserves

Proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations-prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined, and exclude escalations based upon future conditions.

Our policies regarding internal controls over the recording of reserves are structured to objectively estimate our oil and natural gas reserve quantities and values in compliance with SEC regulations. Users of this information should be aware that the process of

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estimating quantities of crude oil and natural gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering, and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history, and continual reassessment of the viability of production under varying economic conditions. Consequently, material revisions to existing reserve estimates occur from time to time.

The estimates of oil, natural gas and NGL reserves in this report are based on reserve reports, substantially all of which were prepared by independent petroleum engineers. To achieve reasonable certainty, our engineers relied on an analysis and reporting software system designed specifically for reserves management that has been demonstrated to yield results with consistency and repeatability. Technical and economic data used include, but are not limited to, updated production data, well performance, formation logs, geological maps, reservoir pressure tests, and wellbore mechanical integrity information.

Our Vice President - Corporate Reserves is the technical person primarily accountable for overseeing the preparation of our reserve estimates. He has a Bachelor of Sciences degree in Petroleum Engineering and a Masters of Business Administration, and has 27 years of industry experience that includes diverse petroleum engineering roles and reserves management. In addition, he is a member of the Society of Petroleum Engineers.

Our Corporate Reserves department continually monitors asset performance in collaboration with our Resource Development and EOR departments, making reserve estimate adjustments, as necessary, to ensure the most current reservoir information is reflected in reserves estimates. Technical reviews are performed throughout the year by our geologic and engineering staff who evaluate pertinent geological and engineering data. This data, in conjunction with economic data and ownership information, is used in making a determination of proved reserve quantities. Our Corporate Reserve Department currently has a total of six full-time employees, comprised of four degreed engineers and two engineering analysts/technicians.

We have internal guidelines and controls in place to monitor the reservoir data and reporting parameters used in preparing the year-end reserves. Internal controls within the reserve estimation process include:

Our Corporate Reserve Department works closely with the independent petroleum consultants to ensure the integrity, accuracy and timeliness of annual independent reserve estimates. Our internal reserve data is provided each year to the independent petroleum engineering firms of Cawley, Gillespie & Associates, Inc. and Ryder Scott Company, L.P. who prepare reserve estimates for the majority of our proved reserves using their own engineering assumptions and the economic data which we provide. The person responsible for overseeing the preparation of our reserve estimates at Cawley, Gillespie & Associates, Inc. is a registered Professional Engineer with more than 30 years of petroleum consulting experience. The person responsible for overseeing the preparation of our reserve estimates at Ryder Scott Company, L.P. is a licensed Professional Engineer with over 30 years of practical experience in the estimation and evaluation of petroleum reserves. Copies of the summary reserve reports prepared by these independent reserve engineers are attached as exhibits to this annual report.

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The table below shows the percentage of the PV-10 value of our total proved reserves of oil, natural gas and NGLs prepared by us and each of our independent petroleum consultants for the years shown.

 

 

Proved Reserves

The following table summarizes our estimates of net proved oil and natural gas reserves, estimated future net revenues from proved reserves, the PV-10 value, the standardized measure of discounted future net cash flows, and the prices used in projecting those measures over the past three years. All of our reserves are located in the United States. We set forth our definition of PV-10 value (a non-GAAP measure) in the Glossary of Terms at the beginning of this annual report and a reconciliation of the standardized measure of discounted future net cash flows to PV-10 value below under “Non-GAAP Financial Measures and Reconciliations.”

 

 

Our net proved oil and natural gas reserves and PV-10 values consisted of the following:

 

 

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Proved Undeveloped Reserves

 

The following table shows material changes in proved undeveloped reserves that occurred during the year ended December 31, 2015.

 

 

Productive Wells

The following table sets forth the number of productive wells in which we have a working interest and the number of wells we operated at December 31, 2015, by area. Productive wells consist of producing wells and wells capable of producing. We also hold royalty interests in units and acreage in addition to the wells in which we have a working interest. Gross wells is the total number of producing wells in which we have a working interest, and net wells is the sum of our working interest in all producing wells.

 

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Drilling Activity

The following table sets forth information with respect to wells drilled and completed during the periods indicated. Development wells are wells drilled within the proved area of a reservoir to the depth of a stratigraphic horizon known to be productive. Exploratory wells are wells drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir. Productive wells are those that produce commercial quantities of hydrocarbons, exclusive of their capacity to produce at a reasonable rate of return. As of December 31, 2015, we had seven operated wells drilling, completing or awaiting completion.