UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

 

FORM 10-K

 

(Mark One)

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

For the annual period ended: December 31, 2016

OR

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

For the transition period from             to             

Commission file number: 333-173751

 

ALTA MESA HOLDINGS, LP

(Exact name of registrant as specified in its charter)

 

 

Registrant’s telephone number, including area code: 281-530-0991

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    ☒  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  ☒ 

(Explanatory Note: The registrant is a voluntary filer and is not subject to the filing requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934.   However, the registrant 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 would have been required to file such reports) as if it were subject to such filing requirements.)

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 (S229.405 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.  ☒ 

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 definition of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one)

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

 

 

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TABLE OF CONTENTS

 







 

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

The information in this report includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements, other than statements of historical fact included in this report, regarding our strategy, future operations, financial condition, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this report, the words “could”, “should”, “will”, “play”, “believe”, “anticipate”, “intend”, “estimate”, “expect”, “project,”  the negative of such terms and other similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on our current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements described under the heading “Risk Factors” included in this report. These forward-looking statements are based on management’s current belief, based on currently available information, as to the outcome and timing of future events.

Forward-looking statements may include statements about our:

We caution you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control, incident to the exploration for and development and production of oil, gathering and sale natural gas and natural gas liquids. These risks include, but are not limited to, commodity price volatility, low prices for oil, natural gas and/or natural gas liquids, global economic conditions, inflation, increased operating costs, lack of availability of drilling and production equipment, supplies, services and qualified personnel,  uncertainties related to new technologies, geographical concentration of our operations, environmental risks, weather risks, security risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating oil and natural gas reserves and in projecting future rates of production, reductions in cash flow, lack of access to capital, our ability to satisfy future cash obligations, restrictions in our debt agreements, the timing of development expenditures, managing our growth and integration of acquisitions, failure to realize expected value creation from property acquisitions, title defects, limited control over non-operated properties and the other risks described under “Item 1A. Risk Factors” in this report.

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Reserve engineering is a process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reservoir engineers. Specifically, future prices received for production and costs may vary, perhaps significantly, from the prices and costs assumed for purposes of these estimates. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of oil and natural gas that are ultimately recovered. 

Should one or more of the risks or uncertainties described in this report occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements.

All forward-looking statements, expressed or implied, included in this report are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we may issue.

Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this report.



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PART I

Item 1. Business

Overview

Alta Mesa Holdings, LP (“Alta Mesa,” the “Company,” “us,” “our,” or “we”) is a privately-held, independent exploration and production company primarily engaged in the acquisition, exploration, development and production of oil, natural gas and natural gas liquids within the United States. We have transitioned our focus from our diversified asset base composed of a portfolio of conventional assets to an oil and liquids-rich resource play in the eastern portion of the Anadarko Basin in Oklahoma (the “STACK”) with an extensive inventory of drilling opportunities.    



The STACK is an acronym describing both its location—Sooner Trend Anadarko Basin Canadian and Kingfisher County—and the multiple, stacked productive formations present in the area. The STACK is a prolific hydrocarbon system with high oil and liquids-rich natural gas content, multiple horizontal target horizons, extensive production history and high drilling success rates. As of December 31, 2016, we have assembled a highly contiguous position of approximately 100,000 net acres largely in the up-dip, naturally-fractured oil portion of the STACK in eastern Kingfisher County, Oklahoma. As of December 31, 2016, we have over 4,000 identified gross horizontal drilling locations in the STACK, over 2,000 of which we expect to operate. These drilling locations are in our primary target formations comprised of the Osage, Meramec and Oswego. We continue to acquire acreage within and adjacent to our acreage footprint with the goal of operating the drilling, completion and production operations in such locations. At present, we are operating six horizontal drilling rigs in the STACK with plans to increase to eight rigs by the end of 2017.  Of our anticipated capital expenditures for 2017 of $290 million, we have allocated 95% to the STACK.

 

We intend to grow our reserves and production through the development of our multi-year inventory of identified drilling locations within the STACK. From 2012 to December 31, 2016, we increased our STACK production at a compound annual growth rate (“CAGR”) of approximately 88%. We increased our leasehold interests from approximately 45,000 net acres in early 2015 to approximately 100,000 net acres as of December 31, 2016 primarily through the acquisition of largely undeveloped leasehold. 



Our average daily net production in the fourth quarter was approximately 21,000 BOE/d, approximately 15,100 BOE/d of which was contributed by our STACK assets; our December production was approximately 23,100 BOE/d, approximately 17,400 BOE/d of which was contributed by our STACK assets.  On December 31, 2016, High Mesa Inc. purchased from BCE-STACK Development LLC (“BCE”) and contributed interests in 24 producing wells (the “Contributed Wells”) drilled under the joint development agreement to us with an effective date as of October 1, 2016.  See – “Bayou City Joint Development Agreement” below.  Our pro forma fourth quarter average daily net production, including the contributed interests Contributed Wells, was approximately 25,300 BOE/d, approximately 19,400 BOE/d of which was contributed by our STACK assets.  Our pro forma December production, including the contributed interest in the Contributed Wells, was approximately 26,700 BOE/d, approximately 21,000 BOE/d of which was contributed by our STACK assets.

 

Beginning in the early 1990s, our operations in the area later to become known as the STACK were focused on vertical wells, waterfloods and analyzing the commercial productivity of the stacked formations on our acreage.  Since late 2012, however, we have concentrated on the horizontal development of the Mississippian-age Osage and Meramec formations, as well as the Pennsylvanian-age Oswego formation. We intend to expand this activity with horizontal wells to further develop other formations with demonstrated vertical production, including the Pennsylvanian-age Big Lime, Prue, Skinner, Red Fork and Cherokee Shale formations; Mississippian-age Manning Lime formation; Devonian-age Woodford Shale formation; and Silurian-age Hunton Lime formation.

 

We consider our operations in the STACK to be in the early phase of a systematic, long-term development program. Our initial focus has been to delineate the Osage, Meramec and Oswego formations through the drilling of horizontal wells in ten contiguous townships in Kingfisher County and one adjacent township in Garfield County. We have commenced infill development with seven multi-well patterns of three to ten wells each, given that we expect full development of our leasehold to require multiple wells per drilling unit to maximize economic recovery of oil and natural gas from each formation. In addition to our existing horizontal development of the Osage, Meramec and Oswego formations, we also plan to commence the drilling of horizontal wells in the Manning formation in 2017.

As of December 31, 2016, our estimated total proved reserves were approximately 138.8 MMBOE, of which 93% were in the STACK. The estimated total proved reserves in the STACK were approximately 129.6 MMBOE, representing a 93% increase over 2015 year-end estimated proved reserves of 67.0 MMBOE in the STACK.  Our total proved reserve mix is approximately 42% oil, 38% natural gas, and 20% natural gas liquids. 



2016 Highlights

During 2016, we concentrated our efforts on developing our assets in the STACK play.  Highlights from 2016 include:

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Industry Operating Environment and Outlook

The success of our business is highly dependent on the prices we receive for our oil, natural gas and natural gas liquids.  Our industry has been significantly impacted by lower crude oil, natural gas, and natural gas liquids prices beginning in the third quarter of 2014 with oil prices falling below $30.00 per barrel on several occasions during the first quarter of 2016 and natural gas prices declining to $1.64 MMBtu on March 3, 2016.  Commodity prices improved in late 2016 with NYMEX West Texas Intermediate (“NYMEX WTI”) reaching $53.72 per barrel and NYMEX Henry Hub reaching $3.72 per MMBtu on December 31, 2016.  As of March 28, 2017, NYMEX WTI was $48.37 per barrel and NYMEX Henry Hub was $3.10 per MMBtu.  Commodity prices remain unpredictable.  Forecasts can be impacted by many factors, including but not limited to changes in worldwide economic conditions, including the European credit markets; geopolitical activities, including developments in the Middle East, South America and elsewhere; worldwide supply conditions; weather conditions; actions taken by the Organization of Petroleum Exporting Countries; and the value of the U.S. dollar in international currency markets.

We have increased our anticipated capital expenditures, which includes acquisitions, for 2017 to $290 million, which is a 28% increase over the $226 million of capital expenditures in 2016.  Additionally, we anticipate that up to an additional $101 million will be funded for 2017 drilling and completions activity in the STACK by BCE pursuant to our joint development agreement (described below).  Our 2017 outlook is focused on the development of our assets in the STACK and, accordingly, we have allocated approximately 95% of our 2017 capital expenditures to the STACK.  We currently operate six drilling rigs in the STACK and anticipate increasing to eight drilling rigs by the end of 2017, which will result in drilling a total of approximately 150 gross wells in the STACK. Of the total anticipated gross wells to be drilled in 2017, we plan to drill approximately 42 gross wells as part of our joint development agreement with BCE.

Our Strategy



Our primary business objective is to increase value through the execution of the following strategies:

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Our Strengths

We believe that the following strengths provide us with significant competitive advantages and position us to continue to successfully execute our strategies:

Partnership Structure

We are structured as a private partnership.  Since our inception in 1987, we have funded exploration, development and operating activities primarily through cash from operations, contributions by our limited partners, borrowings under our senior secured credit facilities and proceeds from the issuance of senior unsecured notes.

Our partnership agreement currently provides for two classes of limited partners. Our Class A limited partners include our founder, Michael E. Ellis, and other parties. Our sole Class B limited partner is High Mesa, Inc. (“High Mesa”) which has been funded through investments from HPS Investment Partners, LLC (formerly known as Highbridge Principal Strategies LLC) (“HPS”) and Bayou City Energy Management LLC (“Bayou City”) in exchange for 100% of the preferred stock in High Mesa.  HPS and Bayou City are private equity firms that are focused on energy and commodities and that manage other portfolio companies that are engaged in the oil and natural gas industry. With their extensive investment experience in the oil and natural gas industry and their network of industry relationships, we believe that HPS and Bayou City provide us with valuable financial management expertise and assistance in making strategic decisions. HPS and Bayou City and their respective portfolio companies are not prohibited from competing with us to acquire oil and gas properties.

As a limited partnership, our operations and activities are managed by the board of directors (the “Board of Directors”) of our general partner, Alta Mesa Holdings GP, LLC (“General Partner”), and the officers of Alta Mesa Services, LP (“Alta Mesa Services”), an entity wholly owned by us. Our General Partner has two members: (i) Alta Mesa Resources, LP, an entity owned by Michael E. Ellis, the founder, Chief Operating Officer, and Chairman of the Board of Directors of our General Partner, and his spouse and our director, Mickey Ellis and (ii) High Mesa. Alta Mesa Resources, LP holds all of the Class A membership interests of our General Partner, and High Mesa holds all of the Class B membership interests of our General Partner.  Our General Partner’s Board of Directors includes one member nominated by HPS, two members nominated by Bayou City and five members nominated by our Class A limited partners.

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All distributions under our partnership agreement shall first be made to holders of Class B units, until certain provisions are met.  After such provisions are met, distributions shall then be made to holders of Class A and Class B units pursuant to the distribution formulas set forth in our partnership agreement.

The Class B limited partner may require the General Partner to make distributions; however, any distribution must be permitted under the terms of our senior secured revolving credit facility and our senior notes.

Distribution of net cash flow from a Liquidity Event (as defined below) would be made to the Class A and Class B limited partners according to a variable formula as defined in our partnership agreement. A “Liquidity Event” is defined as the first to occur, in one or a series of related transactions, of (i) a disposition of all or substantially of the assets of High Mesa and its subsidiaries to a person that is not an affiliate of High Mesa, (ii) a disposition of all the equity securities of High Mesa, or (iii) the consummation of a public offering of the common equity securities of High Mesa or any of its subsidiaries that hold all of substantially all of High Mesa’s assets on a consolidated basis, and if the public offering is of a subsidiary of High Mesa, the subsequent distribution of the public company equity securities or proceeds obtained in the public offering to the holders of equity securities of High Mesa. The Class B limited partner can, without consent of any other limited partners, request that the General Partner take action to cause us, or our assets, to be sold to one or more third parties.

Reserve and Production Overview

The following table describes our proved reserves and production profile as of December 31, 2016:  

 



Our Properties

STACK, Oklahoma 

As of December 31, 2016, we have assembled a highly contiguous position of approximately 100,000 net acres largely in the up-dip, naturally-fractured oil portion of the STACK in eastern Kingfisher County, Oklahoma, which makes up about 93% of our proved reserves.  This position is characterized by multiple productive zones located at total vertical depths between 4,000 feet and 8,000 feet.    The legacy operations within our acreage are primarily shallow-decline, long-lived oil fields developed on 80-acre vertical well spacing associated with waterfloods in the Oswego, Big Lime and Manning Limestones. We continue to maintain production in these historical pay zones.

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As of December 31, 2016, we had a 73% average working interest in 467 gross producing wells.  We produced 4,768 MBOE net to us from our properties in Oklahoma in 2016, an increase of 48% as compared to 3,218 MBOE in 2015.  Our pro forma production from our properties in Oklahoma, including contributed interests in 24 producing wells by High Mesa Inc., was 5,477 MBOE.  During 2016, we spent approximately $209 million in the STACK for the drilling and completion of wells, as well as other expenditures for facilities and acquisition of leaseholds.  We currently operate six drilling rigs in the STACK for horizontal development.  We plan to increase to eight drilling rigs by the end of 2017, targeting the Mississippian-age Osage, Meramec, and Manning formations and the Pennsylvanian-age Oswego formation with horizontal drilling.    We will also participate in other horizontal wells as a non-operator, primarily targeting the Oswego Lime, Meramec and Osage.    

We have allocated approximately $275 million of our 2017  capital expenditure budget, including acquisition, to the STACK.  In 2017, we plan to drill and complete approximately 150 gross wells in the STACK, which is inclusive of approximately 42 gross wells we expect to be drilled and completed through our joint development agreement at a cost of up to $101 million to be funded by BCE.

Bayou City Joint Development Agreement



In January 2016, we entered into a joint development agreement with BCE, a fund advised by Bayou City, to fund a portion of our drilling operations and to allow us to accelerate development of our STACK acreage. On December 31, 2016, High Mesa purchased from BCE and contributed interests in the Contributed Wells drilled under the joint development agreement to us with an effective date of October 1, 2016.  The reserves from the Contributed Wells were 3.1 MMBOE, primarily classified as proved developed producing reserves.  The pro forma production from the Contributed Wells was an average of 4,300 BOE/d in the fourth quarter of 2016.  The drilling program will fund the development of 80 additional wells, in four tranches of 20 wells each. As of December 31, 2016, 20 additional joint wells have been drilled or spudded leaving 60 joint wells to be drilled under the joint development agreement. Of the approximate 150 gross wells we plan to drill in 2017, 42 are expected to be drilled under the joint development agreement.

 

Under the joint development agreement, BCE has committed to fund 100% of our working interest share up to a maximum average of $3.2 million in drilling and completion costs per well for any tranche. We are responsible for any drilling and completion costs exceeding this limit. In exchange for the payment of drilling and completion costs, BCE receives 80% of our working interest (the “BCE Interest”) in each wellbore, which the BCE Interest will be reduced to 20% of our initial working interest upon BCE achieving a 15% internal rate of return on the wells within in a tranche and automatically further reduced to 12.5% of our initial interest upon BCE achieving a 25% internal rate of return. Following the completion of each joint well, we and BCE will each bear our respective proportionate working interest share of all subsequent costs and expenses related to such joint well.



Market Access



We have favorable access to physical markets for our crude oil, natural gas and NGLs produced from our STACK leasehold. Our operations are located less than 60 miles from the principal North American hub for crude oil in Cushing, Oklahoma, providing access to regional and national refining and petrochemical markets. We are also served by pipelines transporting NGLs to processing centers and market hubs in Kansas and the Gulf Coast region. Numerous natural gas gathering systems and associated processing facilities have been in operation in proximity to our STACK assets for several decades and midstream companies have recently installed more robust gathering infrastructure and modern gas processing facilities to support increasing production volumes in the area. We sell a portion of our natural gas to legacy gas processors, including DCP, Mustang, EnLink, MarkWest and Energy Transfer.

 

In the second quarter of 2016, KFM commissioned a 60 MMcf/d cryogenic gas processing facility within our acreage footprint. This facility receives natural gas from the KFM gathering system, which (i) is designed to accommodate the anticipated larger volumes we expect to produce from multi-well pads and (ii) offers assurance of processing and residue capacity to support future production growth. KFM has commenced a 200 MMcf/d expansion that it expects to be operational in mid-2017.

 

We have committed the oil and natural gas production from our Kingfisher County acreage, not otherwise committed to others, to KFM. As part of the KFM contract, we have secured firm processing rights of 260 MMcf/d at the expanding KFM facility, which provides multiple sales outlets for marketing residue natural gas from our growing STACK production volumes and minimizes the effect of future processing limitations due to overall STACK production increases. Beginning June 1, 2018, our subsidiary, Oklahoma Energy Acquisitions, LP (“Oklahoma Energy”), will have residue natural gas firm transport along the Oneok Gas Transmission pipeline for 100,000 dekatherm per day. There is no minimum volume commitment associated with the KFM contract.  Affiliates of our Class B limited partner, High Mesa, own minority equity interests in KFM, as describe more in detail under “Item 13. Certain Relationships and Related Transactions, and Director Independence — Gathering Agreements.”



Weeks Island Area, South Louisiana



The Weeks Island Area, located in Iberia and St. Mary Parish, Louisiana, contains some of our largest proved developed oil reserves and consists of the Weeks Island and Cote Blanche Island fields.    The Weeks Island field, located in Iberia Parish, Louisiana,

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is a historically-prolific oil field with 55 potential pay zones that are structurally and stratigraphically trapped around a piercement salt dome, which we believe offer significant future opportunities for added production and reserves.  The Cote Blanche Island field, located near Weeks Island field in St. Mary Parish, is also a salt dome structure.  The geology is similar to Weeks Island field, and over the long term we plan on utilizing the same geologic interpretation methods and engineering development techniques at Cote Blanche that we use at Weeks Island field to increase reserves and production. 

As of December 31, 2016, we had a 96% average working interest in a total of 57 gross producing wells, and had identified 7 PUD locations in the Weeks Island Area.  Average daily production from the Weeks Island Area during 2016 was approximately 3,400 BOE/d. 

Other Assets

We conduct operations in other areas and continually evaluate the operations in these areas to determine future development, expansion, acquisition opportunities, and strategic divestiture plans. 

Our Oil and Natural Gas Reserves

The table below summarizes our estimated net proved reserves as of December 31, 2016:  

 





 

The table above represents estimates only. Reserves estimates are based upon various assumptions, including assumptions required by the SEC relating to oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The process of estimating reserves is complex. This process requires significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir. Furthermore, different reserve engineers may make different estimates of reserves and cash flow based on the same available data and these differences may be significant. Therefore, these estimates are not precise. Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves will most likely vary from those estimated. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and natural gas prices and other factors, many of which are beyond our control.  Sustained lower prices will cause the unweighted arithmetic average to decrease over time as the lower prices are reflected in the average price, which may result in the estimated quantities and present values of our reserves being reduced and may necessitate future write-downs. 

Internal Controls Over Reserve Estimates and Qualifications of Technical Persons

Our policies and practices regarding internal controls over the recording of reserves is structured to objectively and accurately estimate our oil and gas reserves quantities and present values in compliance with rules, regulations and guidance provided by the SEC, as well as established industry practices used by independent engineering firms and our peers, and in accordance the 2007 Petroleum Resources Management System sponsored and approved by the Society of Petroleum Engineers, the World Petroleum Council, the American Association of Petroleum Geologists and the Society of Petroleum Evaluation Engineers.  The reserve estimation process begins with our Corporate Planning and Reserves department, which gathers and analyzes much of the data used in estimating reserves. Working and net revenue interests are cross-checked and verified by our land department.  Lease operating and capital expenses are provided by our accounting department and reviewed by the Corporate Planning and Reserves department.  Our

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Vice President of Corporate Planning and Reserves is the technical person primarily responsible for overseeing the preparation of our reserve estimates. His qualifications include the following:

Our methodologies include reviews of production trends, material balance calculations, analogy to comparable properties, and/or volumetric analysis. Performance methods are preferred. Reserve estimates for developed non-producing properties and for undeveloped properties are based primarily on volumetric analysis or analogy to offset production in the same or similar fields.

We maintain internal controls including the following to ensure the reliability of reserves estimations:

Ryder Scott Company, L. P. (“Ryder Scott”), a third party consulting firm, audited 97% of our 2016 proved reserves on a 6:1 MCF/BBL conversion basis. 

Copies of the audit letters issued by Ryder Scott are filed with this report as Exhibits 99.1, 99.2, 99.3, and 99.4. The qualifications of the technical persons at Ryder Scott primarily responsible for overseeing the audit of our reserve estimates are set forth below.

Kevin Gangluff earned a B.S. in Chemical Engineering at the University of Notre Dame and a Masters of Business Administration at the University of Texas at Austin.  Mr. Gangluff is a licensed Professional Engineer in the State of Texas. Based on his educational background, professional training and more than thirty years of practical experience in the estimation and evaluation of petroleum reserves and resources, Mr. Gangluff has attained the professional qualifications as a Reserves Estimator and Reserves Auditor set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers as of February 19, 2007.

Michael Stell earned a B.S. in Chemical Engineering at Purdue University in 1979 and a Master of Science Degree in Chemical Engineering from the University of California, Berkeley, in 1981. Mr. Stell is a licensed Professional Engineer in the State of Texas. Based on his educational background, professional training and over thirty-five years of practical experience in the estimation and evaluation of petroleum reserves, Mr. Stell has attained the professional qualifications as a Reserves Estimator and Reserves Auditor set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers as of February 19, 2007.

The reserve audit by Ryder Scott conformed to the meaning of “reserves audit” as presented in the SEC’s Regulation S-K, Item 1202.

A reserves audit and a financial audit are separate activities with unique and different processes and results. These two activities should not be confused. As currently defined by the SEC within Regulation S-K, Item 1202, a reserves audit is the process of reviewing certain of the pertinent facts interpreted and assumptions underlying a reserves estimate prepared by another party and the rendering of an opinion about the appropriateness of the methodologies employed, the adequacy and quality of the data relied upon, the depth and thoroughness of the reserves estimation process, the classification of reserves appropriate to the relevant definitions used, and the reasonableness of the estimated reserves quantities. A financial audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. A financial audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.

Proved Undeveloped Reserves

At December 31, 2016, we had PUDs of 98.4 MMBOE, or approximately 71% of total proved reserves.

Total PUDs at December 31, 2015 were 44.6 MMBOE, or 57% of our total proved reserves.  The following table reflects the changes in PUDs during 2016: 



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PUDs converted to proved developed reserves were primarily in the STACK, our most active development area.  During 2016, we incurred approximately $8.4 million in expenditures to convert the December 31, 2015 PUDs to proved developed reserves.  In addition, we spent approximately $2.7 million to convert PUDs that were added during 2016 to proved developed reserves, a portion of these drilling costs were funded through the joint development agreement.  Extensions and discoveries were due to increases in PUD reserves associated with our successful drilling activity in the STACK.  In 2016, we had positive revisions of 7,322 MBOE due to increase efficiencies of operations at the KFM plant in Oklahoma, which were partially offset by negative price revisions of 3,357 MBOE. These reserves were moved out of the PUD reserve category in compliance with the SEC five-year rule.  Estimated future development costs, including plugging and abandonment cost (“P&A”), for PUDs remaining are approximately $634.5 million at December 31, 2016.

Under current SEC requirements, PUD reserves may only be booked if they relate to wells scheduled to be drilled within five years of the original date of booking unless specific circumstances justify a longer time.  We will be required to remove our PUDs if we do not drill those reserves within the required five year time frame, unless specific circumstances justify a longer time.  All of our PUDs at December 31, 2016 are scheduled to be drilled within five years of the original date of booking.    The future development of such proved undeveloped reserves is dependent on future commodity prices, costs and other economic assumptions in our forecasts.  Lower prices for oil and natural gas as seen in the recent decline may cause us to forecast less capital to be available for development of our PUDs in the future, which may cause us to decrease the amount of our PUDs we expect to develop within the five-year time frame.  In addition, lower oil and natural gas prices may cause our PUDs to become uneconomic to develop at future SEC pricing, which would cause us to remove them from the proved undeveloped category. 

   

Production, Prices and Production Cost History

The following table sets forth certain information regarding the production volumes, average prices received and average production costs associated with our sale of oil, natural gas, and natural gas liquids for the periods indicated below.  For additional

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information on price calculations, please see information set forth in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, Results of Operations”:   





The following table provides a summary of our production, average sales prices and average production costs for the STACK area, which contributes approximately 93% of our total proved reserves as of December 31, 2016. 







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Delivery Commitments

As of December 31, 2016, we had no commitments to provide a fixed quantity of oil, natural gas or natural gas liquids.



Drilling Activity

The following table sets forth, for each of the three years ended December 31, 2016, 2015 and 2014, the number of net productive and dry exploratory and developmental wells completed, regardless of when drilling was initiated. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation between the number of productive wells drilled, quantities of reserves found or economic value.



Present Activities

As of December 31, 2016, we were drilling 32 gross (10.9 net) wells. 

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Productive Wells

The following table sets forth information with respect to our ownership interest in productive wells as of December 31, 2016:  

 



Of the total well count as of December 31, 2016, 3 gross wells (2.6 net) are multiple completions.     

Productive wells are producing wells, shut-in wells we deem capable of production, wells awaiting for completion, plus wells that are drilled/cased and completed, but awaiting pipeline hook-up.  A gross well is a well in which a working interest is owned.  The number of net wells represents the sum of fractional working interests we own in gross wells.

Developed and Undeveloped Acreage Position

The following table sets forth information with respect to our gross and net developed and undeveloped oil and natural gas acreage under lease as of December 31, 2016, all of which is located in the United States:

 



As is customary in the oil and natural gas industry, we can generally retain an interest in undeveloped acreage through drilling activity that establishes commercial production sufficient to maintain the leases, by paying delay rentals during the remaining primary term of leases, pooling process, automatic extensions or negotiated extensions of the leases, and other terms of the leases such as shut-in payments. The oil and natural gas leases in which we have an interest are for varying primary terms and, if production under a lease continues from developed lease acreage beyond the primary term, we are entitled to hold the lease for as long as oil or natural gas is produced. The oil and natural gas properties consist primarily of oil and natural gas wells and interests in leasehold acreage, both developed and undeveloped.

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Undeveloped Acreage Expirations

The following table sets forth information with respect to our gross and net undeveloped oil and natural gas acreage under lease as of December 31, 2016, all of which is located in the United States, that will expire over the following three years by core area unless production is established within the spacing units covering the acreage prior to the expiration dates:

 



We have lease acreage that is generally subject to lease expirations if initial wells are not drilled within a specified period, generally a period of three to five years.  As is customary in the oil and gas industry, we can retain our interest in undeveloped acreage by maintaining the lease through: (i) the commencing operations for drilling, completion and production operations, (ii) pooling process, (iii) production, (iv) automatic extensions or negotiated extensions of the leases and (v) other terms of the leases such as shut-in payments.  As of December 31, 2016, the vast majority of our acreage does not have associated proved undeveloped reserves, and proved undeveloped reserves attributed to acreage in which the lease expiration date precedes the scheduled initial drilling date is not material. Our leases are mainly fee leases with primary terms of three to five years. We believe that our lease terms are similar to our competitors’ fee lease terms as they relate to both primary term and royalty interests.

Marketing and Customers

The market for our oil and natural gas production depends on factors beyond our control, including the extent of domestic production and imports of oil and natural gas, the proximity and capacity of natural gas pipelines and other transportation facilities, the demand for oil and natural gas, the marketing of competitive fuels and the effect of state and federal regulation. The oil and natural gas industry also competes with other industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers.

We sell the oil and natural gas from several properties we operate primarily through a  marketing agreement with ARM Energy Management, LLC (“AEM”).  We are a part owner of AEM at less than 10%.  AEM markets our oil and natural gas and subsequently sells it under short-term contracts generally with month-to-month pricing based on published regional indices, with differentials for transportation, location, and quality taken into account.  AEM remits monthly collections of these sales to us, and receives a 1% marketing fee.  Our marketing agreement with AEM commenced in June 2013.  The agreement will terminate in 2018, with additional provisions for extensions beyond five years, and for early termination.  During the second half of 2013 and throughout 2014 to 2016, AEM marketed majority of our production from operated fields.  Production from non-operated fields, the most significant of which were our Eagleville field in South Texas, and our Hilltop natural gas field in East Texas prior to their sale, was marketed on our behalf by the operators of those properties.  Production from our interests in Eagleville was sold by the operator, Murphy Oil Corporation.  We sold our remaining interests in Eagleville in the third quarter of 2015.  See “Note 4 — Significant Acquisitions and Divestitures” in the accompanying notes to the consolidated financial statements included elsewhere in this report for additional information.

Natural gas liquids are sold under various contracts with processors typically in the vicinity of the production at spot market rates, after processing costs.

For the year ended December 31, 2016, revenues marketed by AEM were $160.7 million, or 80% of total revenue excluding hedging activities. 

 We believe that the loss of any of our significant customers, or of our marketing agent AEM, would not have a material adverse effect on us because alternative purchasers are readily available.  Trade accounts receivable are not collateralized or otherwise secured.

Competition

We encounter intense competition from other oil and natural gas companies in all areas of our operations, including the acquisition of producing properties and undeveloped acreage. Our competitors include major integrated oil and natural gas companies, numerous independent oil and natural gas companies and individuals. Many of our competitors are large, well-established companies with substantially larger operating staffs and greater capital resources and have been engaged in the oil and natural gas business for a much longer time than us. These companies may be able to pay more for productive oil and natural gas properties, exploratory

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prospects and mineral leases and to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. Larger competitors may be able to absorb the decline in prices for oil and natural gas and the burden of any changes in federal, state and local laws and regulations more easily than we can, which could adversely affect our competitive position. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in this highly competitive environment.

We are also affected by competition for drilling rigs and the availability of related equipment. In the past, the oil and natural gas industry has experienced shortages of drilling rigs, equipment, pipe and personnel, which have delayed development, exploitation and exploration activities. We are unable to predict when, or if, such shortages may occur or how they would affect our exploitation and development program.

We compete for capital in the domestic financial marketplace to fund our exploration and development activities to the extent our operations cannot support them at any given time. See “Item 1A. Risk Factors— Our exploration, exploitation, development and acquisition operations will require substantial capital expenditures. We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a decline in our production and reserves.”

Seasonality of Business

 

Weather conditions affect the demand for, and prices of, oil and natural gas. Demand for oil and natural gas is typically higher in the fourth and first quarters resulting in higher prices. Due to these seasonal fluctuations, results of operations for individual quarterly periods may not be indicative of the results that may be realized on an annual basis.



Oklahoma Forced Pooling Process

 

In the past we have used, and we expect to continue to use, the Oklahoma “forced pooling” process to ensure all working interest owners participate in drilling and spacing units for wells we propose to drill as operator on our STACK acreage. Where applicable, this process allows us to increase our working interest in those units.  Any such increase in working interest would lead to a proportionate increase in our share of the production and reserves associated with any such successfully drilled well. Under Oklahoma law, if a party proposes to drill the initial well to a particular formation in a specific drilling and spacing unit but cannot obtain the agreement of all other oil and natural gas interest holders and other leaseholders within the unit as to how the unit should be developed, the party may commence a “forced pooling” process. Under current regulations, drilling and spacing units for our targeted horizons in our STACK acreage are based on drilling a maximum of four to eight horizontal wells, depending on the formation, on a land section consisting of 640 acres. In a forced pooling action, which is common in Oklahoma, the proposed operator files an application for a pooling order with the Oklahoma Corporation Commission (“OCC”) and names all other persons with the right to drill the unit as respondents. The proposed operator is required to demonstrate in an administrative proceeding that it has made a good faith effort to bargain with all of the respondents prior to filing its application. The fair market value of the mineral interests in the unit is determined in the administrative proceeding by reference to market transactions involving nearby oil and natural gas rights, especially what has been paid for mineral leases in the particular drilling and spacing unit and the immediately surrounding drilling and spacing units.

 

Assuming the application is granted and a forced pooling order is granted, the respondents then have 20 days to elect either to participate in the proposed well or accept fair market value for their interest, usually in the form of a cash payment, an overriding royalty, or some combination, based on the fair market value established and approved through the administrative hearing. The pooling order usually also addresses the time frame for drilling the well and provides for the manner in which future wells within the unit may be drilled. The applicant for the pooling order is ordinarily designated as the operator of the wells subject to the pooling order.

 

The availability of forced pooling means that it normally is difficult for a small number of owners to block or delay the drilling of a particular well proposed by another interest holder. Exploration and production companies in Oklahoma often negotiate to lease as much of the mineral interests in a particular area as are readily available at acceptable rates, and then use the forced pooling process to proceed with the desired development of the well. In this manner, we have the ability to expand into and develop areas near our existing acreage even if we are unable to lease all of the mineral interests in those areas.

 

As a result of forced pooling processes, we have increased our working interest in approximately 95% of the 112 total operated horizontal wells we have drilled on our STACK acreage since January 1, 2014. In those wells in which forced pooling proceedings were initiated, we increased our working interest by an average of approximately 15% of our initial working interest in the drilling unit. In one instance in 2016, we proposed and drilled a well as operator in a section where our working interest ownership was initially approximately 10%, which through the implementation of the forced pooling process increased our working interest to approximately 90%. In recent years, the collective working interest of third party owners of mineral rights in these drilling units who have elected to participate in these wells has been low, which we believe could largely be attributed to the absence of available capital following the substantial oil and gas price downturns that commenced in late 2014. Due to the increased interest in the STACK as an economic play in the current price and cost environment, we believe that third party interest holders may be more likely to bear their

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share of the costs of the proposed future wells on our acreage. Nevertheless, we expect that forced pooling will continue to increase our leasehold interests within of our STACK acreage. The successful use of forced pooling to increase our working interest in proposed wells that are attributed undeveloped reserves is not reflected in our reserve reports.

Title to Properties

As is customary in our industry, a preliminary review of title records, which may include opinions or reports of appropriate professionals or counsel, is made at the time we acquire properties. We believe that our title to all of the various interests set forth above is satisfactory and consistent with the standards generally accepted in the oil and gas industry, subject only to immaterial exceptions that do not detract substantially from the value of the interests or materially interfere with their use in our operations. The interests owned by us may be subject to one or more royalty, overriding royalty or other outstanding interests (including disputes related to such interests) customary in the industry. The interests may additionally be subject to obligations or duties under applicable laws, ordinances, rules, regulations and orders of arbitral or governmental authorities. In addition, the interests may be subject to burdens such as net profits interests, liens incident to operating agreements and current taxes, development obligations under oil and gas leases and other encumbrances, easements and restrictions, none of which detract substantially from the value of the interests or materially interfere with their use in our operations.

Employees

As of December 31, 2016, we had 241 full-time employees. We are not a party to any collective bargaining agreements and have not experienced any strikes or work stoppages. We believe our relationships with our employees are good. From time to time, we utilize the services of independent contractors to perform various field and other services. See “Item 13. Certain Relationships and Related Transactions, and Director Independence.”

Insurance 

In accordance with industry practice, we maintain insurance against some, but not all, of the operating risks to which our business is exposed. We currently have insurance policies that include coverage for general liability (includes sudden and accidental pollution), physical damage to our oil and gas properties, control of well, auto liability, marine liability, worker’s compensation and employer’s liability, among other things.

Currently, we have general liability insurance coverage up to $1 million per occurrence, which includes sudden and accidental environmental liability coverage for the effects of pollution on third parties arising from our operations. Our insurance policies contain maximum policy limits and in most cases, deductibles (generally ranging from $25,000 to $1.8 million) that must be met prior to recovery. These insurance policies are subject to certain customary exclusions and limitations. In addition, we maintain excess liability coverage, which is in addition to and triggered if the general liability per occurrence limit is reached.

Our offshore reserves are not a significant portion of our total reserves; the fields are in declining production with no drilling activity. Our consolidated balance sheets include asset retirement liabilities which we believe are sufficient to cover the eventual costs of dismantlement and abandonment. We believe that due to the nature of the operations in these fields, and the limited activity, the risk of environmental damage is not as high as it would be in an actively drilling offshore field. Our insurance program includes property damage, pollution liability, and control of well. The property damage coverage extends to total loss of the equipment (not the reserves) with replacement cost coverage retained on one of the five fields. The pollution coverage, which is applicable to both offshore and onshore events, is $10 million per incident with a $100,000 deductible.

We require all of our third-party contractors, including those that perform hydraulic fracturing operations, to sign master service agreements in which they agree to indemnify us for injuries and deaths of the service provider’s employees as well as contractors and subcontractors hired by the service provider. Similarly, we generally agree to indemnify each third-party contractor against claims made by our employees and other contractors. Additionally, each party generally is responsible for damage to its own property. We do not currently have any insurance policies in effect that are intended to provide coverage for losses solely related to hydraulic fracturing operations.

We re-evaluate the purchase of insurance, coverage limits and deductibles annually. Future insurance coverage for the oil and gas industry could increase in cost and may include higher deductibles or retentions. In addition, some forms of insurance may become unavailable in the future or unavailable on terms that are economically acceptable. No assurance can be given that we will be able to maintain insurance in the future at rates that we consider reasonable and we may elect to self-insure or maintain only catastrophic coverage for certain risks in the future.

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Environmental and Occupational Safety and Health Matters

Our oil and natural gas exploration and production operations are subject to stringent federal, state and local laws and regulations governing occupational safety and health, the discharge of materials into the environment and environmental protection. Numerous governmental agencies, including the U.S. Environmental Protection Agency (“EPA”) and analogous state agencies have the power to enforce compliance with these laws and regulations and the permits issued under them, often requiring difficult and costly actions. These laws and regulations may, among other things:

 

 

 

These laws, rules and regulations often impose difficult and costly compliance measures that carry substantial administrative, civil and criminal penalties and may result in remedial or corrective action obligations, occurrence of delays or cancellations in the permitting, performance or expansion of projects and in issuance of orders enjoining performance in particular areas for non-compliance.

 

The trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment, for example, the EPA has identified environmental compliance by the energy extraction sector as one of its enforcement initiatives for fiscal years 2017 to 2019, although the outlook for this initiative remains unclear with the change in Presidential administration. Consequently, any changes in environmental laws and regulations or re-interpretation of enforcement policies that result in more stringent and costly well drilling, construction, completion or water management activities, or waste handling, storage transport, disposal or remediation requirements could have a material adverse effect on our financial position and results of operations. We may be unable to pass on such increased compliance costs to our customers. Moreover, accidental releases or spills may occur in the course of our operations, and we cannot assure you that we will not incur significant costs and liabilities as a result of such releases or spills, including any third-party claims for damage to property, natural resources or persons. Historically, our environmental compliance costs have not had a material adverse effect on our results of operations; however, there can be no assurance that such costs will not be material in the future or that such future compliance will not have a material adverse effect on our business and operating results.

The following is a summary of some of the more significant existing environmental and occupational safety and health laws, and regulations, as amended from time to time, to which our business operations are subject.

Non-hazardous and Hazardous Wastes and Hazardous Substances Handling

The federal Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes regulate the generation, transportation, treatment, storage, disposal and cleanup of non-hazardous and hazardous wastes. Pursuant to rules issued by the EPA, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. In the course of our operations, we generate some amounts of ordinary industrial wastes that may be regulated as hazardous wastes. Drilling fluids, produced waters, and most of the other wastes associated with the exploration, development and production of oil or natural gas, if properly handled, are currently exempt from regulation as hazardous waste under RCRA and, instead, are regulated under RCRA’s less stringent non-hazardous waste provisions, state laws or other federal laws. However, it is possible that certain oil and natural gas drilling and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future. For example, following the filing of a lawsuit in the U.S. District Court for the District of Columbia in May 2016 by several non-governmental environmental groups against the EPA for the agency’s failure to timely assess its RCRA Subtitle D criteria regulations for oil and gas wastes, EPA and the environmental groups entered into an agreement that was finalized in a consent decree issued by the District Court on December 28, 2016. Under the decree, the EPA is required to propose no later than March 15, 2019, a rulemaking for revision of certain Subtitle D criteria regulations pertaining to oil and gas wastes or sign a determination that revision of the regulations is not necessary. If EPA proposes a rulemaking for revised oil and gas waste regulations, the Consent Decree requires that the EPA take final action following notice and comment rulemaking no later than July 15, 2021. A

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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 waste, which could have a material adverse effect on our financial condition and results of operations.

The federal Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), also known as the Superfund law, and comparable state laws impose liability, without regard to fault or legality of conduct, on classes of persons considered to be responsible for the release of a “hazardous substance” (or in the case of state laws, other classes of materials) into the environment. Under CERCLA, such persons may be subject to joint and several, strict liability for costs of investigation and remediation and for natural resource damages without regard to fault or legality of the original conduct, on certain classes of persons with respect to the release into the environment of hazardous substances. These classes of persons, or so-called potentially responsible parties (“PRPs”) include the current and past owners or operators of a site where the hazardous substance release occurred and anyone who disposed or arranged for the disposal of a hazardous substance released at the site. CERCLA also authorizes the EPA and, in some instances, third parties to take actions in response to threats to public health or the environment and to seek to recover from the PRPs the costs of such action. Many states have adopted comparable or more stringent state statutes. We generate materials in the course of our operations that may be regulated as hazardous substances.

 

We currently own, lease or operate and in the past have owned, leased or operated numerous properties that have been used for oil and natural gas exploration and production for many years. Although we believe we have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes or hydrocarbons may have been released on or under the properties owned or leased by us, or on or under other locations, including offsite locations, where such materials have been taken for treatment or disposal. In addition, some of these properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or hydrocarbons were not under our control. These properties and the materials disposed or released on them may be subject to CERCLA, RCRA and analogous state laws. In the future, we could be required to remediate property, including groundwater, containing or impacted by previously disposed materials (including wastes disposed or released by prior owners or operators, or property contamination, including groundwater contamination by prior owners or operators) or to perform remedial plugging or pit closure operations to prevent future contamination, the costs of which could be material.



Water Discharges and Subsurface Injections

The Federal Water Pollution Control Act, also known as the Clean Water Act (“CWA”) and analogous state laws impose restrictions and strict controls with respect to the discharge of pollutants, including discharges, spills and leaks of oil and hazardous substances, into state waters and waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. Spill prevention, control and countermeasure plan requirements imposed under the CWA require appropriate containment berms and similar structures to help prevent the contamination of regulated waters in the event of a spill, rupture or leak. In addition, the CWA and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities.

 

The CWA also prohibits the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by a permit issued by the U.S. Army Corps of Engineers (“Army Corps”). The EPA has issued final rules outlining its position on the federal jurisdictional reach over waters of the United States. This interpretation by the EPA may constitute an expansion of federal jurisdiction over waters of the United States. The rule was stayed nationwide by the U.S. Sixth Circuit Court of Appeals in October 2015 as that appellate court and several other courts hear lawsuits opposing implementation of the rule. In January 2017, the United States Supreme Court accepted review of the rule to determine whether jurisdiction rests with the federal district or appellate courts. Litigation surrounding this rule is ongoing. In February 2017, President Trump signed an executive order directing the EPA and the Army Corps to begin a process to revise or rescind these rules; the agencies published a notice of intent on March 6, 2017 to review and rescind or revise the rules and the U.S. Department of Justice filed a motion with the U.S. Supreme Court on March 6, 2017 requesting a court stay of its review of the rules. The outlook for these rules is unclear.  Federal and state regulatory agencies can impose administrative, civil and criminal penalties, as well as require remedial or mitigation measures, for non-compliance with discharge permits or other requirements of the CWA and analogous state laws and regulations. The primary federal law related to oil spill liability is the Oil Pollution Act (“OPA”), which amends and augments oil spill provisions of the CWA and imposes certain duties and liabilities on certain “responsible parties” related to the prevention of oil spills and damages resulting from such spills in or threatening United States waters or adjoining shorelines. A liable “responsible party” includes the owner or operator of an onshore facility, vessel or pipeline that is a source of an oil discharge or that poses the substantial threat of discharge, or in the case of offshore facilities, the lessee or permittee of the area in which a discharging facility is located. The OPA assigns joint and several liability, without regard to fault, to each liable party for oil removal costs and a variety of public and private damages. Although defenses exist to the liability imposed by the OPA, they are limited.

 

Our underground injection operations are regulated pursuant to the Underground Injection Control (“UIC”) program established under the federal Safe Drinking Water Act (“SDWA”) and analogous state and local laws and regulations. The UIC program includes requirements for permitting, testing, monitoring, record keeping and reporting of injection well activities, as well as a prohibition against the migration of fluid containing any contaminant into underground sources of drinking water. State regulations require a

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permit from the applicable regulatory agencies to operate underground injection wells. Although we monitor the injection process of our wells, any leakage from the subsurface portions of the injection wells could cause degradation of fresh groundwater resources, potentially resulting in suspension of our UIC permit, issuance of fines and penalties from governmental agencies, incurrence of expenditures for remediation of the affected resource and imposition of liability by third-parties claiming damages for alternative water supplies, property and personal injuries. A change in UIC disposal well regulations or the inability to obtain permits for new disposal wells in the future may affect our ability to dispose of produced waters and other substances, which could affect our business.

 

Furthermore, in response to recent seismic events near underground disposal wells used for the disposal by injection of produced water resulting from oil and natural gas activities, federal and some state agencies are investigating whether such wells have caused increased seismic activity, and some states have restricted, suspended or shut down the use of such disposal wells. In response to these concerns, regulators in some states have imposed, or are considering imposing, additional requirements in the permitting of produced water disposal wells or otherwise to assess any relationship between seismicity and the use of such wells. For example, Oklahoma issued new rules for injection wells in 2014 that imposed certain permitting and operating restrictions and reporting requirements on disposal wells in proximity to faults and also, from time to time, has developed and implemented plans directing certain wells where seismic incidents have occurred to restrict or suspend disposal well operations. The OCC has implemented the National Academy of Science’s “traffic light system,” in determining whether new injection wells should be permitted, permitted only with special restrictions, or not permitted at all. In addition, the OCC has established rules requiring operators of certain produced water injection wells in seismically-active areas, or Areas of Interest, within the Arbuckle formation of the state to, among other things, conduct mechanical integrity testing or make certain demonstrations of such wells’ depth that, depending on the depth, could require the plugging back of such wells and/or the reduction of volumes disposed in such wells. As a result of these measures, the OCC from time to time has developed and implemented plans calling for injection wells within Areas of Interest where seismic incidents have occurred to restrict or suspend disposal operations in an attempt to mitigate the occurrence of such incidents. Increased regulation and attention given to induced seismicity could lead to greater opposition, including litigation, to oil and natural gas activities utilizing injection wells for produced water disposal. Court decisions or the adoption of any new laws, regulations or directives that restrict our ability to dispose of produced water generated by production and development activities, whether by plugging back the depths of disposal wells, reducing the volume of produced water disposed in such wells, restricting injection well locations or otherwise, or by requiring us to shut down injection wells, could significantly increase our costs to manage and dispose of this produced water, which could have a material adverse effect on our financial condition and results of operations.



Hydraulic Fracturing

Many of our development projects require hydraulic fracturing procedures to economically develop the formations. Generally, we perform two types of hydraulic fracturing. In the STACK play, we perform hydraulic fracturing in horizontally drilled wells. These procedures are more extensive, time-consuming and expensive than hydraulic fracturing of vertical wells. We also perform hydraulic fracturing in vertical wells in our East Texas fields, including primarily Urbana and Cold Springs (both in East Texas); among the target zones are the Wilcox and Frio formations.

Currently, most hydraulic fracturing activities are regulated at the state level, as the SDWA’s UIC program exempts EPA regulation of most hydraulic fracturing except for hydraulic fracturing activities involving the use of diesel. However, several federal agencies have asserted regulatory authority or pursued investigations over certain aspects of the hydraulic fracturing process. For example, in December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources, concluding that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources “under some circumstances,” including water withdrawals for fracturing in times or areas of low water availability; surface spills during the management of fracturing fluids, chemicals or produced water; injection of fracturing fluids into wells with inadequate mechanical integrity; injection of fracturing fluids directly into groundwater resources; discharge of inadequately treated fracturing wastewater to surface waters; and disposal or storage of fracturing wastewater in unlined pits. In other examples, in June 2016, the EPA published an effluent limit guideline final rule prohibiting the discharge of wastewater from onshore unconventional oil and natural gas extraction facilities to publicly owned wastewater treatment plants and, in 2014, the EPA asserted regulatory authority pursuant to the UIC program over hydraulic fracturing activities involving the use of diesel and issued guidance covering such activities. Also, the BLM published a final rule that established new or more stringent standards relating to hydraulic fracturing on federal and American Indian lands but, in June 2016 a Wyoming federal judge struck down this final rule, finding that the BLM lacked authority to promulgate the rule, and that decision is currently being appealed by the federal government.  However, on March 15, 2017, the BLM filed a motion in the appeal, asking the court to hold the case in abeyance pending rescission of the rule. Additionally, in 2014, the EPA published an advanced notice of public rulemaking regarding Toxic Substances Control Act reporting of the chemical substances and mixture used in hydraulic fracturing. From time to time, the U.S. Congress has introduced, but not adopted, legislation to provide for federal regulation of hydraulic fracturing and to require disclosure of chemicals used in the fracturing process.

Many states, including Oklahoma, where we conduct operations, and other regional and local regulatory authorities have enacted, and other states or other regional and local authorities are considering, laws or other regulatory initiatives on hydraulic fracturing, including disclosure requirements and regulations that could restrict or prohibit drilling in general or hydraulic fracturing in

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particular, in certain circumstances. Some states have also considered or adopted other restrictions or regulations on drilling and completion operations, including requirements regarding casing and cementing of wells; testing of nearby water wells; restrictions on access to, and usage of, water; and restrictions on the type of chemical additives that may be used in hydraulic fracturing operations. States could elect to prohibit high-volume hydraulic fracturing altogether, following the approach taken by the State of New York in 2015. In addition to state laws, local land use restrictions, such as city ordinances, may restrict drilling in general and/or hydraulic fracturing in particular, although Oklahoma has taken steps to limit the authority of local governments to regulate oil and natural gas development. The issuance of any laws, regulations or other regulatory initiatives that impose new obligations on, or significantly restrict hydraulic fracturing, could make it more difficult or costly for us to perform hydraulic fracturing activities and thereby affect our production and increase our cost of doing business. Such increased costs and any delays or curtailments in our production activities could have a material adverse effect on our business, prospects, financial condition, results of operations and liquidity.

Air Emissions

Our operations are subject to the federal Clean Air Act (“CAA”) and comparable state laws and implementing regulations that restrict the emission of air pollutants from many sources through air emissions standards, construction and operating permit programs and the imposition of other compliance standards. 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 strictly comply with stringent air permit requirements or utilize specific equipment or technologies to control emissions of certain pollutants. The need to obtain permits has the potential to delay our projects or development of oil and natural gas projects.

 

Over the next several years, we may incur certain capital expenditures for air pollution control equipment or other air emissions related issues. For example, in October 2015, the EPA issued a final rule under the CAA, lowering the National Ambient Air Quality Standard for ground-level ozone from the current standard of 75 parts per million to 70 parts per million under both the primary and secondary standards. State implementation of these revised standards could result in stricter permitting requirements, delay or prohibit our ability to obtain such permits, and result in increased expenditures for pollution control equipment, the costs of which could be significant.  Also, the EPA finalized separate rules under the CAA in June 2016 regarding criteria for aggregating multiple sites into a single source for air-quality permitting purposes applicable to the oil and natural gas industry.  This rule could cause small production facilities such as tank batteries and compressor stations, on an aggregate basis, to be deemed a major source, thereby triggering more stringent air permitting requirements and increasing our expenditures for permitting and pollution control equipment.  Additionally, the EPA issued final CAA regulations in 2012 that include NSPS for completions of hydraulically fractured natural gas wells and issued added CAA regulations in June 2016 that include new emissions standards for methane and additional standards for volatile organic compounds from certain new, modified and reconstructed equipment and processes in the oil and natural gas source category, including production activities. Compliance with these and other air pollution control and permitting requirements has the potential to delay the development of oil and natural gas projects, increase our costs and reduce the demand for the oil and natural gas that we produce.



Climate Change Regulation and Legislation

Climate change continues to attract considerable public and scientific attention. As a result, numerous proposals have been made and are likely to continue to be made at the international, national, regional and state levels of government to monitor and limit emissions of greenhouse gases (“GHGs”). These efforts have included consideration of cap-and-trade programs, carbon taxes, GHG reporting and tracking programs and regulations that directly limit GHG emissions from certain sources.

 

At the federal level, no comprehensive climate change legislation has been implemented to date. The EPA has, however, adopted regulations under the CAA that, among other things, establish PSD construction and Title V operating permit reviews for GHG emissions from certain large stationary sources that are already potential sources of significant, or criteria, pollutant emissions. Sources subject to these permitting requirements must meet “best available control technology” standards for those GHG emissions. Additionally, the EPA has adopted rules requiring the monitoring and annual reporting of GHG emissions from specified GHG emission sources in the United States, including, among others, onshore and offshore oil and gas production, processing, transmission, storage and distribution facilities, which include certain of our operations.

 

Federal agencies also have begun directly regulating emissions of methane, a GHG, from oil and natural gas operations. In June 2016, the EPA published Subpart OOOOa, requirements for certain new, modified or reconstructed facilities in the oil and natural gas sector to reduce these methane gas and volatile organic compound emissions. These Subpart OOOOa standards will expand the previously issued Subpart OOOO, requirements issued in 2012 by using certain equipment-specific emissions control practices. Additionally, in December 2015, the United States joined the international community at the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France that prepared an agreement requiring member countries to review and “represent a progression” in their intended nationally determined contributions, which set GHG emission reduction goals every five years beginning in 2020. This “Paris Agreement” was signed by the United States in April 2016 and entered into force in November 2016; however, this agreement does not create any binding obligations for nations to limit their GHG emissions but, rather,

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includes pledges to voluntarily limit or reduce future emissions.  With the change in Presidential administration, the ongoing commitment of the United States to the Paris Agreement is unclear.  

 

The adoption and implementation of any international, federal or state legislation, regulations or other regulatory initiatives that requires reporting of GHGs or otherwise restricts emissions of GHGs from our equipment and operations could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, acquire emissions allowances or comply with new regulatory or reporting requirements, including the imposition of a carbon tax, which one or more developments could have an adverse effect on our business, financial condition and results of operations. Moreover, such new legislation or regulatory programs could also increase the cost to the consumer, and thereby reduce demand for oil and gas, which could reduce the demand for the oil and natural gas we produce and lower the value of our reserves.

 

Finally, it should be noted that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events. If such effects were to occur, our development and production operations have the potential to be adversely affected. Potential adverse effects could include damages to our facilities from powerful winds or rising waters in low lying areas, disruption of our production activities because of climate related damages to our facilities, our costs of operations potentially arising from such climatic effects, less efficient or non-routine operating practices necessitated by such climate effects or increased costs for insurance coverage in the aftermath of such effects. Significant physical effects of climate change could also have an indirect effect on our financing and operations by disrupting the transportation or process-related services provided by midstream companies, service companies or suppliers with whom we have a business relationship. At this time, we have not developed a comprehensive plan to address the legal, economic, social or physical impacts of climate change on our operations.



Activities on Federal Lands

 

Oil and natural gas exploration and production activities on federal lands, including Indian lands, may be subject to the federal National Environmental Policy Act (“NEPA”), which requires federal agencies, including the EPA, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an Environmental Assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment. All of our current exploration and production activities, as well as proposed exploration and development plans, on federal lands require governmental permits that are subject to the requirements of NEPA. This process has the potential to delay or impose additional conditions and costs upon the development of oil and natural gas projects. Authorizations under NEPA are also subject to protest, appeal or litigation, any or all of which may delay or halt projects. Moreover, depending on the mitigation strategies recommended in the Environmental Assessments or Environmental Impact Statement, we could incur added costs, which may be significant.



Occupational Safety and Health Matters

 

We are subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”) and comparable state statutes whose purpose is to protect the health and safety of workers. In addition, the OSHA hazard communication standard, the federal Emergency Planning and Community Right-to-Know Act and comparable state statutes and any implementing regulations require that we organize and/or disclose information about hazardous materials used or produced in our operations and that this information be provided to employees, state and local governmental authorities and citizens.



Other Laws and Regulations

Our operations are also subject to regulations governing the handling, transportation, storage and disposal of naturally occurring radioactive materials. Furthermore, owners, lessees and operators of natural gas and oil properties are also subject to increasing civil liability brought by surface owners and adjoining property owners. Such claims are predicated on the damage to or contamination of land resources occasioned by drilling and production operations and the products derived therefrom, and are often based on negligence, trespass, nuisance, strict liability or fraud. 

Other Regulation of the Oil and Natural Gas Industry

The oil and natural gas industry is extensively regulated by numerous federal, state and local authorities. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations that are binding on the oil and natural gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production.

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The availability, terms and cost of transportation significantly affect sales of oil and natural gas. The interstate transportation of oil and natural gas is subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters, primarily by the Federal Energy Regulatory Commission, (the “FERC”). Federal and state regulations govern the rates and other terms for access to oil and natural gas pipeline transportation. FERC’s regulations for interstate oil and natural gas transmission by pipeline in some circumstances may also affect the intrastate transportation of oil and natural gas by other means.

 

Although oil and natural gas sales prices are currently unregulated, the federal government historically has been active in the area of oil and natural gas sales regulation. We cannot predict whether new legislation to regulate oil and natural gas sales might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures, and what effect, if any, the proposals might have on our operations. Sales of condensate, oil and natural gas liquids are not currently regulated and are made at market prices.

Exports of U.S. Crude Oil Production, Natural Gas and Liquefied Natural Gas

 

The federal government has recently ended its decades-old prohibition of exports of oil produced in the lower 48 states of the United States. It is too recent an event to determine the impact this regulatory change may have on our operations or our sales of oil. The general perception in the industry is that ending the prohibition of exports of oil produced in the United States will be positive for producers of U.S. oil. In addition, the U.S. Department of Energy (the “DOE”) authorizes exports of natural gas, including exports of natural gas by pipelines connecting U.S. natural gas production to pipelines in Mexico, which are expected to increase significantly with the changes taking place in the Mexican government’s regulation of the energy sector in Mexico. In addition, the DOE authorizes the export of LNG through LNG export facilities, the construction of which are regulated by FERC. In the third quarter of 2016, the first quantities of natural gas produced in the lower 48 states of the U.S. were exported as LNG from the first of several LNG export facilities being developed and constructed in the U.S. Gulf Coast region. While it is also too recent an event to determine the impact this change may have on our operations or our sales of natural gas, the perception in the industry is that this will be a positive development for producers of U.S. natural gas.



Drilling and Production

Our operations are subject to various types of regulation at the federal, state and local level. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. The state, and some counties and municipalities, in which we operate also regulate one or more of the following:

 

 

State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties. Some states allow forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of oil and natural gas we can produce from our wells or limit the number of wells or the locations at which we can drill. 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. States do not regulate wellhead prices or engage in other similar direct regulation, but we cannot assure you that they will not do so in the future. The effect of such future regulations may be to limit the amounts of oil and natural gas that may be produced from our wells, which could negatively affect the economics of production from these wells or to limit the number of locations we can drill.

 

Federal, state and local regulations provide detailed requirements for the abandonment of wells, closure or decommissioning of production facilities and pipelines and for site restoration in areas where we operate. The U.S. Army Corps of Engineers and many other state and local authorities also have regulations for plugging and abandonment, decommissioning and site restoration. Although

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the U.S. Army Corps of Engineers does not require bonds or other financial assurances, some state agencies and municipalities do have such requirements.



Forced Pooling in Oklahoma

 

The pooling process before the OCC provides a mechanism to develop a unit when two or more of its owners cannot voluntarily agree to pool their interests for the purposes of drilling and development. This procedure, which is standard in an actively developed field in Oklahoma, is specific to a given reservoir. The parties that are the recipient of pooling applications and orders under the OCC may elect to: (i) lease their unleased minerals for stated terms; (ii) participate in the well and pay their proportionate share of costs; or (iii) be bought out for fair, just and reasonable compensation determined by the OCC. Under this process, we pooled 68 sections in 2016 and on average increased our interest in the 68 units by 15%. 



Natural Gas Sales and Transportation

 

Historically, federal legislation and regulatory controls have affected the price of the natural gas we produce and the manner in which we market our production. FERC has jurisdiction over the transportation and sale for resale of natural gas in interstate commerce by natural gas companies under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. Since 1978, various federal laws have been enacted which have resulted in the complete removal of all price and non-price controls for sales of domestic natural gas sold in “first sales,” which include all of our sales of our own production.



Under the Energy Policy Act of 2005 (“EPAct”), Congress amended the Natural Gas Act (“NGA”) to give FERC) substantial enforcement authority to prohibit the manipulation of natural gas markets and enforce its rules and orders, including the ability to assess substantial civil penalties.  EPAct also amended the NGA to authorize FERC to “facilitate transparency in markets for the sale or transportation of physical natural gas in interstate commerce,” pursuant to which authorization FERC now requires natural gas wholesale market participants, including a number of entities that may not otherwise be subject to FERC’s traditional NGA jurisdiction, to report information annually to FERC concerning their natural gas sales and purchases. FERC requires any wholesale market participant that sells 2.2 million MMBtus or more annually in “reportable” natural gas sales to provide a report, known as FERC Form 552, to FERC. Reportable natural gas sales include sales of natural gas that utilize a daily or monthly gas price index, contribute to index price formation, or could contribute to index price formation, such as fixed price transactions for next-day or next-month delivery.

 

FERC also regulates interstate natural gas transportation rates, terms and conditions of natural gas service, and the terms under which we as a shipper may use interstate natural gas pipeline capacity, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas and for the release of our excess, if any, natural gas pipeline capacity. Commencing in 1985, FERC promulgated a series of orders, regulations and rule-makings that significantly fostered competition in the business of transporting and marketing gas. Today, interstate pipeline companies are required to provide nondiscriminatory transportation services to producers, marketers and other shippers, regardless of whether such shippers are affiliated with an interstate pipeline company. FERC’s initiatives have led to the development of a competitive, open access market for natural gas purchases and sales that permits all purchasers of natural gas to buy gas directly from third-party sellers other than pipelines. However, the natural gas industry historically has been very heavily regulated; therefore, we cannot guarantee that the less stringent regulatory approach currently pursued by FERC and Congress will continue indefinitely into the future nor can we determine what effect, if any, future regulatory changes might have on our natural gas related activities.

 

Under FERC’s current regulatory regime, interstate transportation services must be provided on an open-access, non-discriminatory basis at cost-based rates or at market-based rates if the transportation market at issue is sufficiently competitive.  The FERC-regulated tariffs, under which interstate pipelines provide such open-access transportation service, contain strict limits on the means by which a shipper releases its pipeline capacity to another potential shipper, which provisions include FERC’s “shipper-must-have-title” rule. Violations by a shipper (i.e., a pipeline customer) of FERC’s capacity release rules or shipper-must-have-title rule could subject a shipper to substantial penalties from FERC. 



Gathering service, which occurs on pipeline facilities located upstream of FERC-jurisdictional interstate transmission services, is regulated by the states onshore and in state waters.  Depending on changes in the function performed by particular pipeline facilities, FERC has in the past reclassified certain FERC-jurisdictional transportation facilities as non-jurisdictional gathering facilities, and FERC has reclassified certain non-jurisdictional gathering facilities as FERC-jurisdictional transportation facilities. Any such changes could result in an increase to our costs of transporting gas to point-of-sale locations.

 

The pipelines used to gather and transport natural gas being produced by us are also subject to regulation by the U.S. Department of Transportation (“DOT”) under the Natural Gas Pipeline Safety Act of 1968, as amended, the Pipeline Safety Act of 1992, as reauthorized and amended (“Pipeline Safety Act”), and the Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011. The DOT Pipeline and Hazardous Materials Safety Administration (“PHMSA”) has established a risk-based approach to determine which gathering pipelines are subject to regulation and what safety standards regulated gathering pipelines must meet. In

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March 2016, the PHMSA issued a Notice of Proposed Rulemaking proposing to revise the Pipeline Safety Regulations applicable to the safety of onshore gas transmission and gathering pipelines, including both high consequence areas (“HCAs”) and non-HCAs.

 

Oil and NGLs Sales and Transportation

 

Sales of oil, condensate and natural gas liquids are not currently regulated and are made at negotiated prices. Nevertheless, Congress could reenact price controls in the future.

 

Our sales of oil and natural gas liquids are also affected by the availability, terms and costs of transportation. The rates, terms and conditions applicable to the interstate transportation of oil and natural gas liquids by pipelines are regulated by the FERC, as common carriers, under the Interstate Commerce Act. The FERC has implemented a simplified and generally applicable ratemaking methodology for interstate oil and natural gas liquids pipelines to fulfill the requirements of Title XVIII of the Energy Policy Act of 1992 comprised of an indexing system to establish ceilings on interstate oil and natural gas liquids pipeline rates. 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 materially different way than such regulation will affect the operations of our competitors.

 

Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this open access standard, common carriers must offer service to all shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by prorationing provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to oil pipeline transportation services generally will be available to us to the same extent as to our competitors.

 

Any transportation of our crude oil, natural gas liquids and purity components (ethane, propane, butane, iso-butane and natural gasoline) by rail is also subject to regulation by the DOT’s PHMSA and the DOT’s Federal Railroad Administration (“FRA”) under the Hazardous Materials Regulations at 49 CFR Parts 171-180, including Emergency Orders by the FRA and new regulations being proposed by the PHMSA, arising due to the consequences of train accidents and the increase in the rail transportation of flammable liquids.

 

In October 2015, the PHMSA issued proposed new safety regulations for hazardous liquid pipelines, including a requirement that all hazardous liquid pipelines have a system for detecting leaks and establish a timeline for inspections of affected pipelines following extreme weather events or natural disasters.

 

State Regulation

 

Texas regulates the drilling for, and the production, gathering and sale of, oil and natural gas, including imposing severance taxes and requirements for obtaining drilling permits. Texas currently imposes a 4.6% severance tax on oil production and a 7.5% severance tax on natural gas production. States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of oil and natural gas resources. States may regulate rates of production and may establish maximum daily production allowables from oil and natural gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but we cannot assure you that they will not do so in the future. The effect of these regulations may be to limit the amount of oil and natural gas that may be produced from our wells and to limit the number of wells or locations we can drill.

 

Oklahoma currently imposes on all new wells, both horizontal and vertical, drilled on or after July 1, 2015, a tax 2% of gross production for the first 36 months of production and then at 7% thereafter. There will still be different treatment for a limited number of wells defined as enhanced recovery projects, production enhancement projects, inactive wells and economically at-risk oil or gas leases. Horizontal wells drilled prior to July 1, 2015, will continue to be taxed at 1% for 48 months after production commences. Deep wells drilled prior to July 1, 2015, will continue to be taxed at 4% for 48 months, while most other wells drilled prior to July 1, 2015, will be taxed at 7% throughout their productive life. In response to a recent significant earthquake, federal and Oklahoma state regulators imposed limitations on disposal of produced water in two counties. On September 12, 2016, federal and state regulators expanded and modified those emergency orders limiting disposal activity in the two-county area. Multiple wells shut down immediately after the earthquake are being allowed to resume operations with volume limits.

 

Louisiana severance tax laws are more complex than those of other states. Different schedules of taxes are imposed based on the different hydrocarbons produced. The basic (and highest) rate for natural gas is $0.164 per Mcf for full rate wells. The basis (and highest) rate for oil is 12.5% of value for full rate oil and condensate. There is a severance tax exemption for oil and gas produced from horizontal wells. Last year, Louisiana imposed on operators of wells a security deposit requirement for plugging and abandonment obligations. Those who own between 11 and 99 wells pay a deposit of $250,000. The fee is $500,000 for every 100 wells. Owners of single wells pay by the depth. The deposit is $7 per foot for the first 3,000 feet with lower rates the deeper the well is drilled.

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The petroleum industry is also subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to resource conservation and equal employment opportunity. We do not believe that compliance with these laws will have a material adverse effect on us.



Other Regulation

In addition to the regulation of oil and natural gas pipeline transportation rates, the oil and natural gas industry generally is subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to occupational safety, resource conservation and equal employment opportunity.

General Corporate Information

Alta Mesa Holdings, LP is a Texas limited partnership founded in 1987 with principal offices at 15021 Katy Freeway, Suite 400, Houston, Texas 77094. We can be reached at (281) 530-0991 and our website address is www.altamesa.net. Information on the website is not part of this report.

Item 1A. Risk Factors

Each of the following risk factors could adversely affect our business, operating results and financial condition. It is not possible to foresee or identify all such factors. Investors should not consider this list an exhaustive statement of all risks and uncertainties. This report also contains forward-looking statements that involve risks and uncertainties. Our actual results may differ from those anticipated in these forward-looking statements as a result of both the risks described below and factors described elsewhere in this report. Please read the section above entitled “Cautionary Statement Regarding Forward-Looking Statements” for further discussion of these matters.

Our exploration, exploitation, development and acquisition operations will require substantial capital expenditures. We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a decline in our production and reserves.

The oil and natural gas industry is capital intensive. We have made and expect to continue to make substantial capital expenditures in our business for the exploration, exploitation, development and acquisition of oil and natural gas reserves. Our capital expenditures for 2016 totaled $226 million including acquisitions. As a result of the current price environment, we have increased our budgeted capital expenditures for 2017 to approximately $290 million including acquisitions. We have funded development and operating activities primarily through equity capital raised from our affiliates, through borrowings, through the issuance of debt, and through internal operating cash flows.  We intend to finance our future capital expenditures predominantly with cash flows from operations. If necessary, we may also access capital through proceeds from potential asset dispositions, borrowings under our senior secured revolving credit facility and the future issuance of debt and/or equity securities. Our cash flow from operations and access to capital are subject to a number of variables, including:

 

 

If our revenues or the borrowing base under our senior secured revolving credit facility decrease as a result of lower commodity prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to conduct our operations at expected levels. Our senior secured revolving credit facility may restrict our ability to obtain new debt financing. If additional capital is required, we may not be able to obtain debt and/or equity financing on terms favorable to us, or at all. If cash generated by operations or available under our senior secured revolving credit facility is not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our operations relating to development of our prospects, which in turn could lead to a decline in our reserves and production and could adversely affect our business, results of operations, financial conditions and ability to make payments on our outstanding indebtedness.

External financing may be required in the future to fund our growth. We may not be able to obtain additional financing, and financing under our senior secured revolving credit facility may not be available in the future. Without additional capital resources, we may be unable to pursue and consummate acquisition opportunities as they become available, and we may be forced to limit or defer

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our planned oil and natural gas development program, which will adversely affect the recoverability and ultimate value of our oil and natural gas properties, in turn negatively affecting our business, financial condition and results of operations.

Oil and natural gas prices are highly volatile and depressed prices can significantly and adversely affect our financial condition and results of operations.

Our revenue, profitability and cash flows depend upon the prices for oil, natural gas and natural gas liquids. The prices we receive for oil and natural gas production are volatile and a decrease in prices can significantly and adversely affect our financial results and impede our growth, including our ability to maintain or increase our borrowing capacity, to repay current or future indebtedness and to obtain additional capital on attractive terms. Changes in oil and natural gas prices have a significant impact on the value of our reserves and on our cash flows.

Historically, world-wide oil and natural gas prices and markets have been subject to significant change and may continue to be in the future. In particular, the prices of oil and natural gas declined dramatically after the second half of 2014. From this decline in 2014 through December 31, 2015, based on daily settlements of monthly contracts traded on the NYMEX, the average price for a barrel of oil ranged from a high of $105.15 in June 2014 to a low of $37.33 in December 2015, and the price for an MMBtu of natural gas ranged from a high of $5.56 in February 2014 to a low of $2.03 in November 2015. Oil prices continued to fluctuate during 2016. Based on daily settlements of monthly contracts traded on the NYMEX, the average price for the twelve months ended December 31, 2016 for a barrel of oil ranged from a high of $52.17 in December 2016 to a low of $30.62 in February 2016, and the price for an MMBtu of natural gas ranged from a high of $3.23 in December 2016 to a low of $1.71 in March 2016.

Continued fluctuations in oil and natural gas prices, further price declines or any other unfavorable market conditions could have a material adverse effect on our financial condition and on the carrying value of our proved reserves. The average realized price, excluding hedge settlements, at which we sold oil in 2016 was $40.91 per barrel compared to $47.54 per barrel in 2015 and $92.27 per barrel in 2014. Because the oil price we are required to use to estimate our future net cash flows is the average first day of the month price over the twelve months prior to the date of determination of future net cash flows, the full effect of falling prices may not be reflected in our estimated net cash flows for several quarters.  We review the carrying value of our properties on a quarterly basis and once incurred, a write-down in the carrying value of our properties is not reversible at a later date, even if prices increase.



Prices for oil and natural gas may fluctuate widely in response to relatively minor changes in supply and demand, market uncertainty and a variety of additional factors that are beyond our control, such as:

 

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Substantially all of our production is sold to purchasers under contracts with market-based prices. Continued lower oil and natural gas prices will reduce our cash flows and may reduce the present value of our reserves.



Our business strategy involves the use of the latest available horizontal drilling, completion and production technology, which involve risks and uncertainties in their application.

 

Our operations involve the use of the latest horizontal drilling, completion and production technologies, as developed by us and our service providers, in an effort to improve efficiencies in recovery of hydrocarbons. Use of these new technologies may not prove successful and could result in significant cost overruns or delays or reduction in production, and in extreme cases, the abandonment of a well. The difficulties we face drilling horizontal wells include:

 

Difficulties that we face while completing our wells include the following:  

In addition, certain of the new techniques we are adopting may cause irregularities or interruptions in production due to offset wells being shut in and the time required to drill and complete multiple wells before any such wells begin producing. Furthermore, the application of technology developed in drilling, completing and producing in one productive formation may not be successful in other prospective formations with little or no horizontal drilling history. If our use of the latest technologies does not prove successful, our drilling and production results may be less than anticipated or we may experience cost overruns, delays in obtaining production or abandonment of a well. As a result, the return on our investment will be adversely affected, we could incur material write-downs of unevaluated properties or undeveloped reserves and the value of our undeveloped acreage and reserves could decline in the future.



If oil and natural gas prices decrease, we anticipate that the borrowing base under our senior secured revolving credit facility, which is revised periodically, may be reduced, which would negatively impact our borrowing ability.

 

Lower prices could reduce our cash flows to a level that would require us to borrow to fund our 2017 capital budget. Lower oil and natural gas prices may also reduce the amount of oil and natural gas that we can produce economically. Substantial decreases in oil and natural gas prices could render uneconomic a significant portion of our identified drilling locations. This may result in significant downward adjustments to our estimated proved reserves and, as a result, a decline in the borrowing base under our senior secured revolving credit facility. As a result, a substantial or extended decline in oil and natural gas prices may materially and adversely affect our future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures.



Our identified drilling locations are scheduled over many years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling. In addition, we may not be able to raise the substantial amount of capital that would be necessary to drill such locations.

 

Our management team has specifically identified and scheduled certain drilling locations as an estimation of our future multi-year drilling activities on our existing acreage. These locations represent a significant part of our growth strategy. Our ability to drill and develop identified locations depends on a number of uncertainties, including oil, natural gas and NGLs prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, gathering system and pipeline transportation constraints, access to and availability of water sourcing and distribution systems, regulatory approvals and other factors. Because of these uncertainties, we do not know if the potential well locations we have identified will ever be drilled or if we will be able to produce natural gas or oil from these or any other locations. In addition, unless production is established within the spacing units covering the undeveloped acres on which some of the potential locations are located, the leases for such acreage will expire. As such, our actual drilling activities may materially differ from those presently identified.

 

Furthermore, our estimate of the number of our net drilling locations is based on a number of assumptions, which may prove to be incorrect. For example, we have estimated the number of net drilling locations based on our expected working interests in each gross drilling location based on our existing working interest associated with our acreage applicable to such drilling location and any assumed dilution of such working interest based on any expected unitization of such acreage with adjacent properties controlled by

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third parties. Our assumptions regarding the impact on any such unitization on our working interest in our gross drilling locations may be incorrect and may result in more dilution of our working interest than anticipated, which would result in a reduction of our net drilling locations.

In addition, we will require significant additional capital over a prolonged period in order to pursue the development of these locations, and we may not be able to raise the capital required. Any drilling activities we are able to conduct on these potential locations may not be successful or allow us to add additional proved reserves to our overall proved reserves or may result in a downward revision of our estimated proved reserves, which could have a material adverse effect on our future business and results of operations.



Certain of our undeveloped leasehold assets are subject to leases that will expire over the next several years unless production is established on units containing acreage.

 

Leases on oil and natural gas properties typically have a term of three to five years, after which they expire unless, prior to expiration, a well is drilled and production of hydrocarbons in paying quantities is established. Although the majority of our reserves are located on leases that are held by production, we do have provisions in some of our leases that provide for the lease to expire unless certain conditions are met, such as drilling having commenced on the lease or production in paying quantities having been obtained within a defined time period. If commodity prices remain low or we are unable to fund our anticipated capital program, there is a risk that some of our existing proved reserves and some of our unproved inventory could be subject to lease expiration or a requirement to incur additional leasehold costs to extend the lease. The cost to renew such leases may increase significantly, and we may not be able to renew such leases on commercially reasonable terms or at all. This could result in a reduction in our reserves and our growth opportunities (or the incurrence of significant costs). Although we seek to actively manage our undeveloped properties, our drilling plans for these areas are subject to change based upon various factors, including drilling results, oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, gathering system and pipeline transportation constraints and regulatory approvals.



We depend on successful exploration, exploitation, development and acquisitions to maintain reserves and revenue in the future.

 

In general, the volume of production from oil and natural gas properties declines as reserves are depleted, with the rate of decline depending on each reservoir’s characteristics. Except to the extent that we conduct successful exploration and development activities or acquire properties containing proved reserves, or both, our proved reserves will decline as reserves are produced. Our future oil and natural gas production is, therefore, highly dependent on our level of success in finding or acquiring additional reserves. Additionally, the business of exploring for, developing or acquiring reserves is capital intensive. Recovery of our reserves, particularly undeveloped reserves, will require significant additional capital expenditures and successful drilling operations. To the extent cash flow from operations is reduced and external sources of capital become limited or unavailable, our ability to make the necessary capital investment to maintain or expand our asset base of oil and natural gas reserves would be impaired. In addition, we are dependent on finding partners for our exploratory activity. To the extent that others in the industry do not have the financial resources or choose not to participate in our exploration activities, we may be adversely affected.

Lower oil, natural gas and natural gas liquids prices may cause us to record non-cash write-downs, which could negatively impact our results of operations. 



Accounting rules require that we periodically review the carrying value of our properties for possible impairment. Based on prevailing commodity prices and specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics, and other factors, we may be required to write down the carrying value of our properties. A write-down constitutes a non-cash charge to earnings. We recognized impairment expense during 2016 and 2015 of $16.3 million and $176.8 million, respectively, as a result of lower forecasted commodity prices.  We may incur impairment charges in the future, which could have a material adverse effect on our results of operations for the periods in which such charges are taken.



During 2015 and 2016, we recognized significant impairments of proved oil and gas properties and impairments of unproved oil and gas properties, primarily as a result of lower forecasted commodity prices and changes to our drilling plans. At December 31, 2016, our estimate of undiscounted future cash flows attributable to a certain depletion group with a net book value of approximately $550.8 million indicated that the carrying amount was expected to be recovered; however, this depletion group may be at risk for impairment if oil and natural gas prices decline by 10%. We estimate that, if this depletion group becomes impaired in a future period, we could recognize non-cash impairments in that period in excess of $5.0 million. It is also reasonably foreseeable that prolonged low or further declines in commodity prices, further changes to our drilling plans in response to lower prices or increases in drilling or operating costs could result in other additional impairments.

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Our estimated proved oil and natural gas reserve quantities and future production rates are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or the underlying assumptions will materially affect the quantities and present value of our reserves.

 

Numerous uncertainties are inherent in estimating quantities of oil and natural gas reserves. Our estimates of our proved reserve quantities are based upon our estimated net proved reserves as of December 31, 2016. The process of estimating oil and natural gas reserves is complex, requiring significant decisions and assumptions in the evaluation of available geological, engineering and economic data for each reservoir, and these reports rely upon various assumptions, including assumptions regarding future oil and natural gas prices, production levels and operating and development costs. As a result, estimated quantities of proved reserves and projections of future production rates and the timing of development expenditures may prove to be inaccurate. Over time, we may make material changes to reserve estimates taking into account the results of actual drilling and production. Any significant variance in our assumptions and actual results could greatly affect our estimates of reserves, the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, the classifications of reserves based on risk of recovery and estimates of the future net cash flows. Specifically, future prices received for production and costs may vary, perhaps significantly, from the prices and costs assumed for purposes of these estimates. Sustained lower prices will cause the twelve month weighted average price to decrease over time as the lower prices are reflected in the average price, which may result in the estimated quantities and present values of our reserves being reduced.



The present value of future net revenues from our proved reserves or “PV-10” will not necessarily be the same as the current market value of our estimated proved oil and natural gas reserves.

 

It should not be assumed that the present value of future net revenues from our proved reserves is the current market value of our estimated oil and natural gas reserves. In accordance with SEC requirements, we based the estimated discounted future net cash flows from our proved reserves on the twelve-month unweighted arithmetic average of the closing prices on the first day of each month for the preceding twelve months from the date of the report without giving effect to derivative transactions. Actual future net cash flows from our oil and natural gas properties will be affected by factors such as:

 

 

The timing of both our production and our incurrence of expenses in connection with the development and production of our oil and natural gas properties will affect the timing and amount of actual future net revenues from proved reserves and thus their actual present value. In addition, the 10% discount factor we use when calculating the PV-10 value may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general. Actual future prices and costs may differ materially from those used in the present value estimate. If oil and natural gas prices decline by 10%, then our PV-10 value as of December 31, 2016 would decrease by approximately $236.4 million to $322.2 million.



SEC rules could limit our ability to book additional PUDs in the future.

 

The SEC rules require that, subject to limited exceptions, PUDs may only be booked if they relate to wells scheduled to be drilled within five years after the date of booking. This requirement has limited and may continue to limit our ability to book additional PUDs as we pursue our drilling program. Moreover, we may be required to write down our PUDs if we do not drill or plan on delaying those wells within the required five-year timeframe.

Approximately 71% of our total estimated proved reserves at December 31, 2016 were PUDs requiring substantial capital expenditures and may ultimately prove to be less than estimated.

Recovery of PUDs requires significant capital expenditures and successful drilling operations. At December 31, 2016, approximately 98.4 MMBOE of our total estimated proved reserves were undeveloped. The reserve data included in our reserve reports assumes that substantial capital expenditures will be made to develop non-producing reserves. The calculation of our estimated net proved reserves as of December 31, 2016 assumes that we will spend $634.5 million, including plugging and abandonment costs, to develop our estimated PUDs, including an estimated $189.4 million during 2017. Although cost and reserve estimates attributable to our oil and natural gas reserves have been prepared in accordance with industry standards, we cannot be sure that the estimated costs are accurate. We may need to raise additional capital in order to develop our estimated PUDs over the next five years and we cannot be certain that additional financing will be available to us on acceptable terms, if at all. Additionally, continued declines in

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commodity prices will reduce the future net revenues of our PUDs and may result in some projects becoming uneconomical.  As a result of depressed oil and natural gas prices, we reduced the budgeted capital expenditures for the development of undeveloped reserves in 2016.  These delays in the development of reserves could force us to reclassify certain of our proved reserves as unproved reserves. Further, our drilling efforts may be delayed or unsuccessful and actual reserves may prove to be less than current reserve estimates, which, could have a material adverse effect on our financial condition, results of operations and future cash flows.

As part of our exploration and development operations, we have expanded, and expect to further expand, the application of horizontal drilling and multi-stage hydraulic fracture stimulation techniques. The utilization of these techniques requires substantially greater capital expenditures as compared to the completion cost of a vertical well. The incremental capital expenditures are the result of greater measured depths and additional hydraulic fracture stages in horizontal wellbores.



We may experience difficulty in achieving and managing future growth.

 

We believe that our future success depends on our ability to manage the growth that we have experienced and the demands from increased responsibility on management personnel. The following factors could present difficulties:

 

 

Our operating results could be adversely affected if we do not successfully manage these potential difficulties.

 

Additionally, future growth may place strains on our resources and cause us to rely more on project partners and independent contractors, possibly negatively affecting our financial condition and results of operations. Our ability to grow will depend on a number of factors, including:



We depend upon several significant purchasers for the sale of most of our oil and natural gas production. The loss of one or more of these purchasers could, among other factors, limit our access to suitable markets for the oil, natural gas and NGLs we produce.

 

The availability of a ready market for any oil, natural gas and NGLs we produce depends on numerous factors beyond the control of our management, including but not limited to the extent of domestic production and imports of oil, the proximity and capacity of pipelines, the availability of skilled labor, materials and equipment, the effect of state and federal regulation of oil and natural gas production and federal regulation of oil and gas sold in interstate commerce. In addition, we depend upon several significant purchasers for the sale of most of our oil and natural gas production. While we believe that we would be able to locate alternative purchasers, we cannot assure you that we will continue to have ready access to suitable markets for our future oil and natural gas production.



We will rely on drilling to increase our levels of production. If our drilling is unsuccessful, our financial condition will be adversely affected.

 

The primary focus of our business strategy is to increase production levels by drilling wells. Although we were successful in drilling in the past, we cannot provide assurance that we will continue to maintain production levels through drilling. Our drilling involves numerous risks, including the risk that we will not encounter commercially productive oil or natural gas reservoirs. We must incur significant expenditures to drill and complete wells. The costs of drilling and completing wells are often uncertain, and it is possible that we will make substantial expenditures on drilling and not discover reserves in commercially viable quantities.

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We may be unable to make attractive acquisitions or successfully integrate acquired businesses, and any inability to do so may disrupt our business and hinder our ability to grow.

 

In the future we may make acquisitions of businesses or properties that complement or expand our current business. We may not be able to identify attractive acquisition opportunities. Even if we do identify attractive acquisition opportunities, we may not be able to complete the acquisition or do so on commercially acceptable terms. We may not be able to obtain contractual indemnities from sellers for liabilities incurred prior to our purchase of the business or property. No assurance can be given that we will be able to identify additional suitable acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on acceptable terms or successfully acquire identified targets. In the course of our due diligence, we may not inspect every aspect of a business we acquire and, we cannot necessarily observe structural and environmental problems, such as pipe corrosion or groundwater contamination, when an inspection is made.

 

The success of any completed acquisition will depend on our ability to integrate effectively the acquired business into our existing operations. The process of integrating acquired businesses may involve unforeseen difficulties and may require a disproportionate amount of our managerial and financial resources. Our failure to achieve consolidation savings, to incorporate the acquired businesses and assets into our existing operations successfully or to minimize any unforeseen operational difficulties could have a material adverse effect on our financial condition and results of operations.

 

In addition, our partnership agreement, our senior secured revolving credit facility and the indenture governing the 7.875% senior unsecured notes due 2024 (the “2024 Notes”) impose certain limitations on our ability to enter into mergers or combination transactions. Our partnership agreement, senior secured revolving credit facility and the indenture governing the 2024 Notes also limit our ability to incur certain indebtedness, which could indirectly limit our ability to engage in acquisitions of businesses.

 

Our business is subject to operational risks that will not be fully insured, which, if they were to occur, could adversely affect our financial condition or results of operations.

 

Our business activities are subject to operational risks, including:

 

 

In addition, a portion of our natural gas production is processed to extract natural gas liquids at processing plants that are owned by others. If these plants were to cease operations for any reason, we would need to arrange for alternative transportation and processing facilities. These alternative facilities may not be available, which could cause us to shut in our natural gas production. Further, such alternative facilities could be more expensive than the facilities we currently use.

 

Any of these events could adversely affect our ability to conduct operations or cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution or other environmental contamination, loss of wells, regulatory penalties, suspension or termination of operations and attorney’s fees and other expenses incurred in the prosecution or defense of litigation.

 

As is customary in the industry, we maintain insurance against some but not all of these risks. Additionally, we may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the perceived risks presented. Losses could therefore occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. The occurrence of an event that is not fully covered by insurance could have a material adverse impact on our business activities, financial condition and results of operations.

 

Drilling for and producing oil and natural gas are high risk activities with many uncertainties that could adversely affect our business, financial condition or results of operations.

 

Our future financial condition and results of operations will depend on the success of our development, acquisition and production activities, which are subject to numerous risks beyond our control, including the risk that drilling will not result in commercially viable oil and natural gas production.

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Our decisions to develop or purchase prospects or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. For a discussion of the uncertainty involved in these processes, see “— Our estimated proved oil and natural gas reserve quantities and future production rates are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or the underlying assumptions will materially affect the quantities and present value of our reserves.”

 

Any material inaccuracies in reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves. In addition, our cost of drilling, completing and operating wells is often uncertain.

 

Further, many factors may curtail, delay or cancel our scheduled drilling projects, including the following:

 

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

To achieve more predictable cash flows and to reduce our exposure to fluctuations in the prices of oil and natural gas, we have entered and may continue to enter into hedging arrangements for a significant portion of our production. As of December 31, 2016, we have hedged approximately 63% of our total forecasted PDP production through 2019 at weighted average annual floor prices ranging from $3.06 per MMBtu to $4.50 per MMBtu for natural gas and $47.68 per Bbl to $50.00 per Bbl for oil, with the majority of the hedged volumes in 2017. If we experience a sustained material interruption in our production, we might be forced to satisfy all or a portion of our hedging obligations without the benefit of the cash flows from our sale of the underlying physical commodity, resulting in a substantial diminution of our liquidity. Lastly, an attendant risk exists in hedging activities that the counterparty in any derivative transaction cannot or will not perform under the instrument and that we will not realize the benefit of the hedge.

Our ability to use hedging transactions to protect us from future price declines will be dependent upon prices at the time we enter into future hedging transactions and our future levels of hedging and, as a result our future net cash flows, may be more sensitive to commodity price changes.

Our policy has been to hedge a significant portion of our near-term estimated production. However, our price hedging strategy and future hedging transactions will be determined at our discretion. We are not under an obligation to hedge a specific portion of our production. The prices at which we hedge our production in the future will be dependent upon commodities prices at the time we enter into these transactions, which may be substantially higher or lower than current prices. Accordingly, our price hedging strategy may not protect us from significant declines in prices received for our future production. Conversely, our hedging strategy may limit our ability to realize cash flows from commodity price increases. It is also possible that a substantially larger percentage of our future production will not be hedged as compared with the next few years, which would result in our oil and natural gas revenues becoming more sensitive to commodity price fluctuations.

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Our hedging transactions expose us to counterparty credit risk.

Our hedging transactions expose us to risk of financial loss if a counterparty fails to perform under a derivative contract.  This risk of counterparty non-performance is of particular concern given the disruptions that have occurred in the financial markets and the significant decline in oil and natural gas prices which could lead to sudden changes in a counterparty’s liquidity, and impair their ability to perform under the terms of the derivative contract. We are unable to predict sudden changes in a counterparty’s creditworthiness or ability to perform. Even if we do accurately predict sudden changes, our ability to negate the risk may be limited depending upon market conditions.  Furthermore, the bankruptcy of one or more of our hedge providers or some other similar proceeding or liquidity constraint, might make it unlikely that we would be able to collect all or a significant portion of amounts owed to us by the distressed entity or entities. 

During periods of falling commodity prices our hedge receivable positions increase, which increases our exposure. If the creditworthiness of our counterparties deteriorates and results in their nonperformance, we could incur a significant loss.



Our use of 2-D and 3-D seismic data is subject to interpretation and may not accurately identify the presence of hydrocarbons, which could adversely affect the results of our drilling operations.

 

Even when properly used and interpreted, 2-D and 3-D seismic data and visualization techniques are only tools used to assist geoscientists in identifying subsurface structures and hydrocarbon indicators and do not enable geoscientists to know whether hydrocarbons are, in fact, present in those structures and the amount of hydrocarbons. We are employing 3-D seismic data technology with respect to certain of our projects. The use of 2-D and 3-D seismic data and other advanced technologies requires greater pre-drilling expenditures than traditional drilling strategies, and we could incur greater drilling and testing expenses as a result of such expenditures, which may result in a reduction in our returns or losses. As a result, our drilling activities may not be successful or economical, and our overall drilling success rate or our drilling success rate for activities in a particular area could decline.

 

We often gather 2-D and 3-D seismic data over large areas. Our interpretation of seismic data delineates those portions of an area that we believe are desirable for drilling. Therefore, we may choose not to acquire option or lease rights prior to acquiring seismic data, and, in many cases, we may identify hydrocarbon indicators before seeking option or lease rights in the location. If we are not able to lease those locations on acceptable terms, we will have made substantial expenditures to acquire and analyze 2-D and 3-D seismic data without having an opportunity to attempt to benefit from those expenditures.



We may be unable to compete effectively with larger companies, which may adversely affect our ability to generate sufficient revenues.

 

The oil and natural gas industry is intensely competitive, and we compete with other companies that have greater resources than us. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties to consummate transactions in a highly competitive market. Many of our larger competitors not only drill for and produce oil and natural gas, but also engage in refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for oil and natural gas properties and evaluate, bid for and purchase a greater number of properties than our financial or human resources permit. In addition, these companies may have a greater ability to continue drilling activities during periods of low commodity prices, to contract for drilling equipment, to secure trained personnel and to absorb the burden of present and future federal, state, local and other laws and regulations. The oil and natural gas industry has periodically experienced shortages of drilling rigs, equipment, pipe and personnel, which has delayed development drilling and other exploitation activities and has caused significant price increases. Competition has been strong in hiring experienced personnel, particularly in the engineering and technical, accounting and financial reporting, tax and land departments. In addition, competition is strong for attractive oil and natural gas producing properties, oil and natural gas companies and undeveloped leases and drilling rights. Our inability to compete effectively with larger companies could have a material adverse impact on our business activities, financial condition and results of operations.

 

The oil and natural gas industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. As others use or develop new technologies, we may be placed at a competitive disadvantage or competitive pressures may force us to implement those new technologies at substantial costs. In addition, other oil and natural gas companies may have greater financial, technical and personnel resources that allow them to enjoy technological advantages and may in the future allow them to implement new technologies before we can. We may not be able to respond to these competitive pressures and implement new technologies on a timely basis or at an acceptable cost. If one or more of the technologies we use now or in the future were to become obsolete or if we are unable to use the most advanced commercially available technology, our business, financial condition and results of operations could be materially adversely affected.

 

Deficiencies of title to our leased interests could significantly affect our financial condition.

 

If an examination of the title history of a property reveals that an oil or natural gas lease or other developed rights has been purchased in error from a person who is not the owner of the mineral interest desired, our interest would substantially decline in value.

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In such cases, the amount paid for such oil or natural gas lease or leases or other developed rights would be lost. It is management’s practice, in acquiring oil and natural gas leases or undivided interests in oil and natural gas leases or other developed rights, not to incur the expense of retaining lawyers to examine the title to the mineral interest to be acquired. Rather, we will rely upon the judgment of oil and natural gas lease brokers or landmen who perform the fieldwork in examining records in the appropriate governmental or county clerk’s office before attempting to acquire a lease or other developed rights in a specific mineral interest.

 

Prior to drilling an oil or natural gas well, however, it is the normal practice in the oil and natural gas industry for the person or company acting as the operator of the well to obtain a preliminary title review of the spacing unit within which the proposed oil or natural gas well is to be drilled to ensure there are no obvious deficiencies in title to the well. Frequently, as a result of such examinations, certain curative work must be done to correct deficiencies in the marketability of the title, such as obtaining affidavits of heirship or causing an estate to be administered. Such curative work entails expense, and it may happen, from time to time, that the operator may elect to proceed with a well despite defects to the title identified in the preliminary title opinion. Our failure to obtain perfect title to our leasehold may adversely impact our ability in the future to increase production and reserves.

We are vulnerable to risks associated with operating in the inland waters region of South Louisiana.

Our operations and financial results could be significantly impacted by unique conditions in the inland waters region of South Louisiana because we explore and produce in that area. As a result of this activity, we are vulnerable to the risks associated with operating in the inland waters region of South Louisiana, including those relating to:



Our operations are substantially dependent on the availability of water. Restrictions on our ability to obtain water may have an adverse effect on our financial condition, results of operations and cash flows.

 

Water is an essential component of shale oil and natural gas exploration and production during both the drilling and hydraulic fracturing processes. Historically, we have been able to purchase water from local land owners and other sources for use in our operations. However, our access to such water supplies may be adversely affected due to reasons such as periods of extended drought, private, third party competition for water in localized areas or the implementation of local or state governmental programs to monitor or restrict the beneficial use of water subject to their jurisdiction for hydraulic fracturing to assure adequate local water supplies. If we are unable to obtain sufficient amounts of water to use in our operations from local sources, our ability to perform hydraulic fracturing operations could be restricted or made more costly, or we otherwise may be unable to economically produce oil and natural gas, which could have an adverse effect on our financial condition, results of operations and cash flows.

 

Our ability to pursue our business strategies may be adversely affected if we incur costs and liabilities due to a failure to comply with environmental laws or regulations or a release of hazardous substances or other wastes into the environment.

 

We may incur significant costs and liabilities as a result of environmental requirements applicable to the operation of our wells, gathering systems and other facilities. These costs and liabilities could arise under a wide range of federal, state and local environmental laws and regulations, including, for example, the following federal laws and their state counterparts, as amended from time to time:

 

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These U.S. laws and their implementing regulations, as well as state counterparts, generally restrict the level of pollutants emitted to ambient air, discharges to surface water, and disposals or other releases to surface and below-ground soils and ground water. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil and criminal penalties, the imposition of investigatory, remedial and corrective actions obligations, the incurrence of capital expenditures, the occurrence of delays in the permitting, development or expansion of projects and the issuance of orders enjoining some or all of our future operations in a particular area. Certain environmental laws and analogous state laws and regulations impose strict joint and several liability, without regard to fault or legality of conduct, for costs required to clean up and restore sites where hazardous substances or other wastes have been disposed of or otherwise released. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, wastes or other materials into the environment. The trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment and more stringent laws and regulations may be adopted in the future. Historically, our environmental compliance costs have not had a material adverse effect on our results of operations; however, there can be no assurance that such costs will not be material in the future or that such future compliance will not have a material adverse effect on our business and operating results.

 

Changes in the legal and regulatory environment governing the oil and natural gas industry, particularly changes in the current Oklahoma forced pooling system, could have a material adverse effect on our business.

 

Our business is subject to various forms of extensive government regulation, including laws and regulations concerning the location, spacing and permitting of the oil and natural gas wells we drill and the disposal of saltwater produced from such wells, among other matters. Changes in the legal and regulatory environment governing our industry, particularly any changes to Oklahoma statutory forced pooling procedures that make forced pooling more difficult to accomplish, could result in increased compliance costs and adversely affect our business and results of our operations.

 

We may have difficulty maintaining our historic levels of success in using current Oklahoma forced pooling process to increase our interests in wells we propose to drill on our STACK acreage due to changes in third party interest owners’ ability or desire to participate in our wells or possible future regulatory changes.

 

In the past we have used, and we expect to continue to use, the Oklahoma “forced pooling” process to increase our working interest in drilling units for wells we propose to drill as operator on our STACK acreage, which could lead to a proportionate increase in our share of the production and reserves associated with any such successfully drilled well. In recent years, the collective working interest of third party owners of mineral rights in our drilling units who have elected to participate in our wells has been relatively low, which we believe could largely be attributed to the absence of available capital following the substantial oil and gas price downturns that commenced in late 2014. Due to the increased interest in the STACK as an economic oil and gas play in the current price and cost environment and the resultant consolidation of acreage in producers with greater access to capital, we believe that third party interest holders may be more likely to bear their share of the costs of the proposed future wells we propose to drill on our acreage. Thus, our ability to use Oklahoma forced pooling procedures to increase our working interest in proposed wells may be more difficult to accomplish. In addition, future changes in laws and regulations in Oklahoma affecting the forced pooling process could result in changes in economics and the level of participation in drilling by third party interest owners and adversely affect our ability to increase our interests in wells that we propose.

 

The adoption of derivatives legislation and regulations by the U.S. Congress related to derivative contracts could have an adverse impact on our ability to hedge risks associated with our business.

 

Title VII of the Dodd-Frank Act establishes federal oversight and regulation of over-the-counter (“OTC”) derivatives and requires the Commodity Futures Trading Commission (the “CFTC”) and the SEC to enact further regulations affecting derivative

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contracts, including the derivative contracts we use to hedge our exposure to price volatility through the OTC market. Although the CFTC and the SEC have issued final regulations in certain areas, final rules in other areas and the scope of relevant definitions and/or exemptions still remain to be finalized.

 

In one of its rulemaking proceedings still pending under the Dodd-Frank Act, the CFTC issued on December 5, 2016, a re-proposed rule imposing position limits for certain futures and option contracts in various commodities (including natural gas) and for swaps that are their economic equivalents. Under the proposed rules on position limits, certain types of hedging transactions are exempt from these limits on the size of positions that may be held, provided that such hedging transactions satisfy the CFTC’s requirements for certain enumerated “bona fide hedging” transactions or positions. A final rule has not yet been issued. Similarly, on December 2, 2016, the CFTC has re-issued a proposed rule regarding the capital a swap dealer or major swap participant is required to set aside with respect to its swap business, but the CFTC has not yet issued a final rule.

 

The CFTC issued a final rule on margin requirements for uncleared swap transactions on January 6, 2016, which includes an exemption from any requirement to post margin to secure uncleared swap transactions entered into by commercial end-users in order to hedge commercial risks affecting their business. In addition, the CFTC has issued a final rule authorizing an exemption from the otherwise applicable mandatory obligation to clear certain types of swap transactions through a derivatives clearing organization and to trade such swaps on a regulated exchange, which exemption applies to swap transactions entered into by commercial end-users in order to hedge commercial risks affecting their business. The mandatory clearing requirement currently applies only to certain interest rate swaps and credit default swaps, but the CFTC could act to impose mandatory clearing requirements for other types of swap transactions. The Dodd-Frank Act also imposes recordkeeping and reporting obligations on counterparties to swap transactions and other regulatory compliance obligations.

 

All of the above regulations could increase the costs to us of entering into financial derivative transactions to hedge or mitigate our exposure to commodity price volatility and other commercial risks affecting our business. While it is not possible at this time to predict when the CFTC will issue final rules applicable to position limits or capital requirements, depending on our ability to satisfy the CFTC’s requirements for a commercial end-user using swaps to hedge or mitigate our commercial risks, these rules and regulations may require us to comply with position limits and with certain clearing and trade-execution requirements in connection with our financial derivative activities. When a final rule on capital requirements for swap dealers is issued, the Dodd-Frank Act may require our current swap dealer counterparties to post additional capital as a result of entering into uncleared financial derivatives with us, which capital requirements rule could increase the costs to us of future financial derivatives transactions. The Volcker Rule provisions of the Dodd-Frank Act may also require our current bank counterparties that engage in financial derivative transactions to spin off some of their derivatives activities to separate entities, which separate entities may not be as creditworthy as the current bank counterparties. Under such rules, other bank counterparties may cease their current business as hedge providers. These changes could reduce the liquidity of the financial derivatives markets thereby reducing the ability of entities like us, as commercial end-users, to have access to financial derivatives to hedge or mitigate our exposure to commodity price volatility.

 

As a result, the Dodd-Frank Act and any new regulations issued thereunder could significantly increase the cost of derivative contracts (including through requirements to post cash collateral), which could adversely affect our capital available for other commercial operations purposes, materially alter the terms of future swaps relative to the terms of our existing bilaterally negotiated financial derivative contracts and reduce the availability of derivatives to protect against commercial risks we encounter.

 

If we reduce our use of derivative contracts as a result of the new requirements, our results of operations may become more volatile and cash flows less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the legislation was intended, in part, to reduce the volatility of oil, natural gas and natural gas liquids prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil, natural gas and natural gas liquids. Our revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on our consolidated financial condition, results of operations or cash flows.

 

We are subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of conducting our operations.

 

Our exploration and production operations are subject to complex and stringent laws and regulations. In order to conduct our operations in compliance with these laws and regulations, we must obtain and maintain numerous permits, approvals and certificates from various federal, state and local governmental authorities. Failure or delay in obtaining regulatory approvals or drilling permits could have a material adverse effect on our ability to develop our properties, and receipt of drilling permits with onerous conditions could increase our compliance costs. In addition, regulations regarding conservation practices and the protection of correlative rights affect our operations by limiting the quantity of oil and natural gas we may produce and sell.

 

We are subject to federal, state and local laws and regulations as interpreted and enforced by governmental authorities possessing jurisdiction over various aspects of the exploration, production and transportation of oil and natural gas. The possibility exists that new laws, regulations or enforcement policies could be more stringent and significantly increase our compliance costs. If

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we are not able to recover the resulting costs through insurance or increased revenues, our financial condition could be adversely affected.

 

Our access to transportation options can also be affected by U.S. federal and state regulation of oil and natural gas production and transportation, general economic conditions and changes in supply and demand. Various proposals and proceedings that might affect the petroleum industry are pending before Congress, FERC, various state legislatures and the courts. The industry historically has been heavily regulated and we cannot provide assurance that the less stringent regulatory approach recently pursued by the FERC and Congress will continue nor can we predict what effect such proposals or proceedings may have on our operations.

 

Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas, technological advances in fuel economy and energy generation devices could reduce demand for oil and natural gas. The impact of the changing demand for oil and natural gas may have a material adverse effect on our business, financial condition, results of operations and cash flows.

 

Should we fail to comply with all applicable statutes, rules, regulations and orders administered by the CFTC or the FERC, we could be subject to substantial penalties and fines.



Under the Energy Policy Act of 2005, FERC has been given greater civil penalty authority under the Natural Gas Act (“NGA”), including the ability to impose penalties of up to $1 million per day for each violation and disgorgement of profits associated with any violation.  While our operations have not been regulated by FERC as a natural gas company under the NGA, FERC has adopted regulations that may subject certain of our otherwise non-FERC jurisdictional operations to FERC annual reporting and posting requirements.  We also must comply with the anti-market manipulation rules enforced by FERC under the NGA.  Under the Commodity Exchange Act (as amended by the Dodd-Frank Act) and regulations promulgated thereunder by the CFTC, the CFTC has also adopted anti-market manipulation, fraud and market disruption rules relating to the prices of commodities, futures contracts, options on futures, and swaps.  Additional rules and legislation pertaining to those and other matters may be considered or adopted by Congress, the FERC, or the CFTC from time to time.  Failure to comply with those statutes, regulations, rules and orders could subject us to civil penalty liability.



Climate change legislation or other regulatory initiatives restricting emissions of GHGs could result in increased operating costs and reduced demand for the oil and natural gas we produce.

 

Climate change continues to attract considerable public and scientific attention. As a result, numerous proposals have been made and may continue to be made at the international, national, regional and state levels of government to monitor and limit emissions of GHGs. These efforts have included consideration of cap-and-trade programs, carbon taxes, GHG reporting and tracking programs and regulations that directly limit GHG emissions from certain sources. At the federal level, no comprehensive climate change legislation has been implemented to date. The EPA has, however, adopted regulations under the CAA that, among other things, establish Potential for Significant Deterioration (“PSD”) construction and Title V operating permit reviews for GHG emissions from certain large stationary sources that are already potential sources of significant, or criteria, pollutant emissions. Sources subject to these permitting requirements must meet “best available control technology” standards for those GHG emissions. Additionally, the EPA has adopted rules requiring the monitoring and annual reporting of GHG emissions from specified GHG emission sources in the United States, including, among others, onshore and offshore oil and gas production, processing, transmission, storage and distribution facilities, which include certain of our operations.

 

Federal agencies also have begun directly regulating emissions of methane, a GHG, from oil and natural gas operations. In June 2016, the EPA published New Source Performance Standards (“NSPS”), known as Subpart OOOOa, that require certain new, modified or reconstructed facilities in the oil and natural gas sector to reduce these methane gas and volatile organic compound emissions. These Subpart OOOOa standards will expand previously issued NSPS published by the EPA in 2012 and known as Subpart OOOO, by using certain equipment-specific emissions control practices.  Moreover, in November 2016, the EPA issued an Information Collection Request (“ICR”) seeking information about methane emissions from facilities and operations in the oil and natural gas industry but on March 2, 2017, the EPA announced that it was withdrawing the ICR so that the agency may further assess the need for the information that it was collecting through the request.    Additionally, in December 2015, the United States joined the international community at the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France that prepared an agreement requiring member countries to review and “represent a progression” in their intended nationally determined contributions, which set GHG emission reduction goals every five years beginning in 2020. This “Paris Agreement” was signed by the United States in April 2016 and entered into force in November 2016. The United States is one of more than 120 nations having ratified or otherwise consented to the agreement; however, this agreement does not create any binding obligations for nations to limit their GHG emissions but, rather, includes pledges to voluntarily limit or reduce future emissions.  With the change in Presidential administration, the ongoing commitment of the United States to the Paris Agreement is unclear.



The adoption and implementation of any international, federal or state legislation, regulations or other regulatory initiatives that requires reporting of GHGs or otherwise restricts emissions of GHGs from our equipment and operations could require us to incur

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increased operating costs, such as costs to purchase and operate emissions control systems, acquire emissions allowances or comply with new regulatory or reporting requirements, including the imposition of a carbon tax, which one or more developments could have an adverse effect on our business, financial condition and results of operations. Moreover, such new legislation or regulatory programs could also increase the cost to the consumer, and thereby reduce demand for oil and gas, which could reduce the demand for the oil and natural gas we produce and lower the value of our reserves.

 

Finally, it should be noted that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events. If such effects were to occur, our development and production operations have the potential to be adversely affected. Potential adverse effects could include damages to our facilities from powerful winds or rising waters in low lying areas, disruption of our production activities because of climate related damages to our facilities, our costs of operations potentially arising from such climatic effects, less efficient or non-routine operating practices necessitated by such climate effects, or increased costs for insurance coverage in the aftermath of such effects. Significant physical effects of climate change could also have an indirect effect on our financing and operations by disrupting the transportation or process-related services provided by midstream companies, service companies or suppliers with whom we have a business relationship. At this time, we have not developed a comprehensive plan to address the legal, economic, social or physical impacts of climate change on our operations.

 

Federal, state and local legislation and regulatory initiatives relating to hydraulic fracturing could increase our costs of doing business, impose additional operating restrictions or delays and adversely affect our production.

 

Hydraulic fracturing is an essential and common practice used to stimulate production of oil and natural gas from dense subsurface rock formations, such as shales. We routinely apply hydraulic fracturing techniques in many of our operations to stimulate production of hydrocarbons, particularly natural gas. The process involves the injection of water, sand and additives under pressure into a targeted subsurface formation to fracture the surrounding rock and stimulate production.

 

Hydraulic fracturing (other than that using diesel) is currently generally exempt from regulation under the SDWA’s UIC program and is typically regulated by state oil and natural gas commissions or similar agencies. However, several federal agencies have asserted regulatory authority or pursued investigations over certain aspects of the process. For example, in December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources, concluding that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources “under some circumstances,” including water withdrawals for fracturing in times or areas of low water availability; surface spills during the management of fracturing fluids, chemicals or produced water; injection of fracturing fluids into wells with inadequate mechanical integrity; injection of fracturing fluids directly into groundwater resources; discharge of inadequately treated fracturing wastewater to surface waters; and disposal or storage of fracturing wastewater in unlined pits. In other examples, in June 2016, the EPA published an effluent limit guideline final rule prohibiting the discharge of wastewater from onshore unconventional oil and natural gas extraction facilities to publicly owned wastewater treatment plants and, in 2014, the EPA asserted regulatory authority pursuant to the UIC program over hydraulic fracturing activities involving the use of diesel and issued guidance covering such activities. Also, the Bureau of Land Management (“BLM”) published a final rule that established new or more stringent standards relating to hydraulic fracturing on federal and American Indian lands but, in June 2016 a Wyoming federal judge struck down this final rule, finding that the BLM lacked authority to promulgate the rule, and that decision is currently being appealed by the federal government. However, on March 15, 2017, the BLM filed a motion in the appeal, asking the court to hold the case in abeyance pending rescission of the rule.  Additionally, in 2014, the EPA published an advanced notice of public rulemaking regarding Toxic Substances Control Act reporting of the chemical substances and mixture used in hydraulic fracturing. From time to time, the U.S. Congress has introduced, but not adopted, legislation to provide for federal regulation of hydraulic fracturing and to require disclosure of chemicals used in the fracturing process.

 

In addition, some states, including Oklahoma where we operate, have adopted, and other states are considering adopting, regulations that restrict or could restrict hydraulic fracturing in certain circumstances and that require the disclosure of the chemicals used in hydraulic fracturing operations. States could elect to prohibit high-volume hydraulic fracturing altogether, following the approach taken by the State of New York in 2015. In addition to state laws, local land use restrictions, such as city ordinances, may restrict drilling in general and/or hydraulic fracturing in particular, although Oklahoma has taken steps to limit the authority of local governments to regulate oil and natural gas development. The issuance of any laws, regulations or other regulatory initiatives that impose new obligations on, or significantly restrict hydraulic fracturing, could make it more difficult or costly for us to perform hydraulic fracturing activities and thereby affect our production and increase our cost of doing business. Such increased costs and any delays or curtailments in our production activities could have a material adverse effect on our business, prospects, financial condition, results of operations and liquidity.

 

Legislation or regulatory initiatives intended to address seismic activity could restrict our ability to dispose of produced water gathered from our drilling and production activities, which could have a material adverse effect on our business.

 

We dispose of produced water gathered from our operations pursuant to permits issued to us or third party vendors by governmental authorities overseeing such disposal activities. While these permits are issued pursuant to existing laws and regulations,

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these legal requirements are subject to change, which could result in the imposition of more stringent permitting or operating constraints or new monitoring and reporting requirements owing to, among other things, concerns of the public or governmental authorities regarding such disposal activities.

 

One such concern relates to recent seismic events near underground injection wells used for the disposal of produced water resulting from oil and natural gas activities. When caused by human activity, such events are called induced seismicity. Developing research suggests that the link between seismic activity and wastewater disposal may vary by region, and that only a very small fraction of the tens of thousands of injection wells have been suspected to be, or have been, the likely cause of induced seismicity. In March 2016, the United States Geological Survey identified six states with the most significant hazards from induced seismicity, including Oklahoma, where we operate. In response to these concerns, regarding induced seismicity, regulators in some states, including Oklahoma, have imposed, and other states are considering imposing, additional requirements in the permitting of produced water injection wells or otherwise to assess any relationship between seismicity and the use of such wells. For example, Oklahoma issued new rules for injection wells in 2014 that imposed certain permitting and operating restrictions and reporting requirements on injection wells in proximity to faults and also, from time to time, developed and implemented plans directing certain wells where seismic incidents have occurred to restrict or suspend injection well operations. The OCC has implemented the National Academy of Science’s “traffic light system,” in determining whether new injection wells should be permitted, permitted only with special restrictions, or not permitted at all. In addition, the OCC has established rules requiring operators of certain produced water injection wells in seismically-active areas, or Areas of Interest, within the Arbuckle formation of the state to, among other things, conduct mechanical integrity testing or make certain demonstrations of such wells’ depth that, depending on the depth, could require the plugging back of such wells and/or the reduction of volumes disposed in such wells. As a result of these measures, the OCC from time to time has developed and implemented plans calling for injection wells within Areas of Interest where seismic incidents have occurred to restrict or suspend disposal operations in an attempt to mitigate the occurrence of such incidents.

 

Also, ongoing lawsuits allege that injection well disposal operations have caused damage to neighboring properties or otherwise violated state and federal rules governing waste disposal. These developments could result in additional regulation and restrictions on the use of injection wells. Increased regulation and attention given to induced seismicity could lead to greater opposition, including litigation, to oil and natural gas activities utilizing injection wells for produced water disposal. Evaluation of seismic incidents and whether or to what extent those events are induced by the injection of produced water into disposal wells continues to evolve, as governmental authorities consider new and/or past seismic incidents in areas where produced water injection activities occur or are proposed to be performed. Court decisions or the adoption of any new laws, regulations or directives that restrict our ability to dispose of produced water generated by production and development activities, whether by plugging back the depths of disposal wells, reducing the volume of produced water disposed in such wells, restricting injection well locations or otherwise or by requiring us to shut down injection wells, could significantly increase our costs to manage and dispose of this produced water, which could have a material adverse effect on our financial condition and results of operations.

 

Laws and regulations pertaining to threatened and endangered species or protective of environmentally sensitive areas could delay or restrict our operations and cause us to incur significant costs.

 

Our operations may be adversely affected by seasonal or permanent restrictions or costly mitigation measures imposed under various federal and state statutes in order to protect endangered or threatened species and their habitats, migratory birds, wetlands and natural resources. Federal statutes, as amended from time to time, that are protective of these species, birds and environmentally sensitive areas include the ESA, the Migratory Bird Treaty Act, the CWA, the CERCLA and the OPA. For example, to the extent that species are listed under the ESA or similar state laws and live in areas where our oil and natural gas exploration and production activities are conducted, our ability to conduct or expand operations and construct facilities could be limited or be forced to incur material additional costs. Moreover, our operations may be delayed, restricted or precluded in protected habitat areas or during certain seasons, such as breeding and nesting seasons.

 

Additionally, the U.S. Fish and Wildlife Service (“FWS”) may designate new or increased critical habitat areas that it believes are necessary for survival of threatened or endangered species, which designation could result in material restrictions to federal land use and private land use and could delay or prohibit land access or oil and natural gas development. As a result of one or more settlements approved by the federal government, the FWS must make determinations on the listing of numerous specified species as endangered or threatened under the ESA pursuant to specified timelines. The designation of previously unidentified endangered or threatened species could indirectly cause us to incur additional costs, cause our operations to become subject to operating restrictions or bans, and limit future development activity in affected areas. If harm to protected species or damages to wetlands, habitat or natural resources occur or may occur, government entities or, at times, private parties may act to prevent oil and natural gas exploration or development activities or seek damages for harm to species, habitat or natural resources resulting from drilling or construction or releases of oil, wastes, hazardous substances or other regulated materials, and, in some cases, may seek criminal penalties. The designation of previously unprotected species as threatened or endangered in areas where we conduct operations could cause us to incur increased costs arising from species protection measures or time delays or limitations on our operations.

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We could experience periods of higher costs if oil and natural gas prices rise or as drilling activity otherwise increases in our area of operations. Higher costs could reduce our profitability, cash flow and ability to pursue our drilling program as planned.

 

Historically, our capital and operating costs typically rise during periods of sustained increasing oil, natural gas and NGL prices. These cost increases result from a variety of factors beyond our control as drilling activity increases, such as increases in the cost of electricity, tubular goods, water, sand and other disposable materials used in fracture stimulation and other raw materials that we and our vendors rely upon; and the cost of services and labor especially those required in horizontal drilling and completion. Since late 2014, oil and natural gas prices declined substantially resulting in decreased levels of drilling activity in the U.S. oil and natural gas industry, including in our area of operations. This led to significantly lower costs of some drilling and completion equipment, services, materials and supplies. As commodity prices rise or stabilize or drilling activity otherwise increases in our area of operations, these lower cost levels may not be sustainable over long periods. Recently, there has been increased drilling activity in the STACK. As a result, such costs may rise thereby negatively impacting our profitability, cash flow and causing us to possibly reconfigure or reduce our drilling program.

 

The third parties on whom we rely for gathering and transportation services are subject to complex federal, state and other laws that could adversely affect the cost, manner or feasibility of conducting our business.

 

The operations of the third parties on whom we rely for gathering and transportation services are subject to complex and stringent laws and regulations that require obtaining and maintaining numerous permits, approvals and certifications from various federal, state and local government authorities. These third parties may incur substantial costs in order to comply with existing laws and regulations. If existing laws and regulations governing such third-party services are revised or reinterpreted, or if new laws and regulations become applicable to their operations, these changes may affect the costs that we pay for such services. Similarly, a failure to comply with such laws and regulations by the third parties on whom we rely could have a material adverse effect on our business, financial condition and results of operations. See “Item 1. Business—Environmental and Occupational Safety and Health Matters” and “Business—Other Regulation of the Oil and Natural Gas Industry” for a description of the laws and regulations that affect the third parties on whom we rely. 

 

We have limited control over activities on properties we do not operate, which could reduce our production and revenues.

 

We have limited control over properties which we do not operate or do not otherwise control operations. If we do not operate or otherwise control the properties in which we own an interest, we do not have control over normal operating procedures, expenditures or future development of the underlying properties. The failure of an operator of our wells to adequately perform operations, an operator’s financial difficulties, including as a result of price volatility or an operator’s breach of the applicable agreements could reduce our production and revenues. The success and timing of our drilling and development activities on properties operated by others, therefore, depends upon a number of factors outside of our control, including the operator’s timing and amount of capital expenditures, expertise and financial resources, inclusion of other participants in drilling wells and use of technology.

 

We may not be able to repurchase our outstanding 2024 Notes upon a change of control.

Under the terms of the indenture governing the 2024 Notes, if we experience certain specific change of control events, we will be required to offer to repurchase all of our outstanding notes at 101% of the principal amount of such  notes plus accrued and unpaid interest to the date of repurchase. We may not have available funds sufficient to pay the change of control purchase price for any or all of the 2024 Notes that might be tendered in the change of control offer.



The definition of change of control in the indenture governing the 2024 Notes includes a phrase relating to the direct or indirect sale, transfer, conveyance or other disposition of “all or substantially all” of our and our restricted subsidiaries’ assets, taken as a whole. Although there is a limited body of case law interpreting the phrase “substantially all”, there is no precise established definition of the phrase under applicable law. Accordingly, the ability of a holder of the 2024 Notes to require us to repurchase such notes as a result of a sale, transfer, conveyance or other disposition of “less than all of our and our restricted subsidiaries” assets taken as a whole to another person or group may be uncertain. Our partnership agreement permits High Mesa to cause our General Partner to initiate a sale of our company to a third party, which sale may be deemed to be a change of control. High Mesa may exercise this right at a time that we do not have sufficient capital or are otherwise prohibited from repurchasing the 2024 Notes. In addition, our senior secured revolving credit facility contains, and any future credit agreement likely will contain, restrictions or prohibitions on our ability to repurchase the 2024 Notes under certain circumstances. If these change of control events occur at a time when we are prohibited from repurchasing the 2024 Notes, we may seek the consent of our lenders to purchase the 2024 Notes or could attempt to refinance the borrowings that contain these prohibitions or restrictions. If we do not obtain our lenders’ consent or refinance these borrowings, we will not be able to repurchase the 2024 Notes. Accordingly, the holders of the 2024 Notes may not receive the change of control purchase price for their notes in the event of a sale or other change of control, which will give the trustee and the holders of the 2024 Notes the right to declare an event of default and accelerate the repayment of the notes.

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Oil and gas exploration and production activities are complex and involve risks that could lead to legal proceedings resulting in the incurrence of substantial liabilities.

 

Like many oil and gas companies, we are from time to time involved in various legal and other proceedings in the ordinary course our business, such as title, royalty or contractual disputes, regulatory compliance matters and personal injury or property damage matters, in the ordinary course of our business. Such legal proceedings are inherently uncertain and their results cannot be predicted. Regardless of the outcome, such proceedings could have an adverse impact on us because of legal costs, diversion of management and other personnel and other factors. In addition, it is possible that a resolution of one or more such proceedings could result in liability, penalties or sanctions, as well as judgments, consent decrees or orders requiring a change in our business practices, which could materially and adversely affect our business, operating results and financial condition. Accruals for such liabilities, penalties or sanctions may be insufficient, and judgments and estimates to determine accruals or range of losses related to legal and other proceedings could change from one period to the next, and such changes could be material.

 

Our affiliates are not limited in their ability to compete with us for acquisition or drilling opportunities. This could cause conflicts of interest and limit our ability to acquire additional assets or businesses.

 

The agreements governing the relationship between our affiliates do not prohibit our affiliates from owning assets or engaging in businesses that compete directly or indirectly with us. For instance, our affiliates may acquire, develop or dispose of additional oil or natural gas properties or other assets in the future, without any obligation to offer us the opportunity to purchase or develop any of those assets. HPS and Bayou City are each part of a larger family of funds, which have significantly greater resources than we have, which may make it more difficult for us to compete for acquisition candidates if our affiliates were to compete against us.

 

We depend on key personnel, the loss of any of whom could materially adversely affect future operations.

 

Our success will depend to a large extent upon the efforts and abilities of our executive officers and key operations personnel. The loss of the services of one or more of these key employees could have a material adverse effect on us. We do not maintain key-man life insurance with respect to any of our employees. Our business will also be dependent upon our ability to attract and retain qualified personnel. Acquiring and keeping these personnel could prove more difficult or cost substantially more than estimated. This could cause us to incur greater costs or prevent us from pursuing our development and exploitation strategy as quickly as we would otherwise wish to do.

 

We operate in an area of high industry activity, which may affect our ability to hire, train or retain qualified personnel needed to manage and operate our assets.

 

Our operations and drilling activity in the STACK are in an area in which industry activity has increased rapidly. As a result, demand for qualified personnel in this area, and the cost to attract and retain such personnel, has increased over the past few years due to competition and may increase substantially in the future. Moreover, our competitors may be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer.

 

Any delay or inability to secure the personnel necessary for us to continue or complete our current and planned development activities could result in oil and gas production volumes being below our forecasted volumes. In addition, any such negative effect on production volumes, or significant increases in costs, could have a material adverse effect on our results of operations, liquidity and financial condition.

 

We may encounter obstacles to marketing our oil and natural gas, which could adversely impact our revenues.

 

The marketability of our production will depend in part upon the availability and capacity of natural gas gathering systems, pipelines and other transportation facilities owned by third parties. Transportation space on the gathering systems and pipelines we utilize is occasionally limited or unavailable due to repairs or improvements to facilities or due to space being utilized by other companies that have priority transportation agreements. Additionally, new fields may require the construction of gathering systems and other transportation facilities. These facilities may require us to spend significant capital that would otherwise be spent on drilling. The availability of markets is beyond our control. If market factors dramatically change, the impact on our revenues could be substantial and could adversely affect our ability to produce and market oil and natural gas.

 

Our senior secured revolving credit facility and the indenture governing the 2024 Notes have restrictive covenants that could limit our growth, financial flexibility and our ability to engage in certain activities.

 

Our senior secured revolving credit facility and the indenture governing the 2024 Notes have restrictive covenants that could limit our growth, financial flexibility and our ability to engage in activities that may be in our long-term best interests. Our senior

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secured revolving credit facility and the indenture governing the 2024 Notes also contain covenants, that, among other things, limit our ability to:

 

 

In addition, our senior secured revolving credit facility requires us to maintain certain financial ratios or to reduce our indebtedness if we are unable to comply with such ratios, which may limit our ability to obtain future financings to withstand a future downturn in our business or the economy in general or to otherwise conduct necessary corporate activities. We may also be prevented from taking advantage of business opportunities that arise because of these limitations. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Senior Notes” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Senior Secured Revolving Credit Facility.”

 

Our failure to comply with these covenants could result in an event of default that, if not cured or waived, could result in the acceleration of all of our indebtedness. If that occurs, we may not be able to make all of the required payments or borrow sufficient funds to refinance such indebtedness. Even if new financing were available at that time, it may not be on terms that are acceptable to us.

 

Any significant reduction in our borrowing base under our senior secured revolving credit facility as a result of the periodic borrowing base redeterminations or otherwise may negatively impact our ability to fund our operations, and we may not have sufficient funds to repay borrowings under our senior secured revolving credit facility if required as a result of a borrowing base redetermination.

 

Availability under our senior secured revolving credit facility is currently subject to a borrowing base of $287.5 million. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Senior Secured Revolving Credit Facility.” The borrowing base is subject to scheduled semiannual and other elective unscheduled borrowing base redeterminations and is based on the value of our oil and natural gas reserves as determined by the lenders under our senior secured revolving credit facility and other factors deemed relevant by our lenders. Declines in prices for oil and natural gas may cause our banks to reduce the borrowing base under our senior secured revolving credit facility. Any significant reduction in our borrowing base as a result of such borrowing base redeterminations or otherwise may negatively impact our liquidity and our ability to fund our operations and, as a result, may have a material adverse effect on our financial condition, results of operations and cash flows. Further, if the outstanding borrowings under our senior secured revolving credit facility were to exceed the borrowing base as a result of any such redetermination, we would be required to repay the excess. We may not have sufficient funds to make such repayments. If we do not have sufficient funds and we are otherwise unable to negotiate renewals of our borrowings or arrange new financing, we may have to sell significant assets. Any such sale could have a material adverse effect on our business and financial results.

 

If we are unable to comply with the restrictions and covenants in our debt agreements, there could be a default under the terms of such agreements, which could result in an acceleration of repayment.

 

If we are unable to comply with the restrictions and covenants in our debt agreements, there could be a default under the terms of these agreements. Our ability to comply with these restrictions and covenants, including meeting financial ratios and tests, may be affected by events beyond our control. As a result, we cannot assure that we will be able to comply with these restrictions and covenants or meet such financial ratios and tests. If we are unable to generate sufficient cash flow and are otherwise unable to obtain funds necessary to meet required payments of principal, premium, if any, and interest on our indebtedness, or if we otherwise fail to comply with the various covenants, including financial and operating covenants in the instruments governing our indebtedness (including covenants in our senior secured revolving credit facility or the indenture governing the 2024 Notes), we could be in default under the terms of the agreements governing such indebtedness. In the event of such a default, the holders of such indebtedness could elect to declare all the funds borrowed thereunder to be due and payable, together with accrued and unpaid interest, the lenders under our senior secured revolving credit facility could terminate their commitments to lend, cease making further loans and institute

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foreclosure proceedings against our assets, and we could be forced into bankruptcy or liquidation. Borrowings under other debt instruments that contain cross-acceleration or cross-default provisions may also be accelerated and become due and payable. If any of these events occur, our assets might not be sufficient to repay in full all of our outstanding indebtedness and we may be unable to find alternative financing. Even if we could obtain alternative financing, it might not be on terms that are favorable or acceptable to us. Additionally, we may not be able to amend our debt agreements or obtain needed waivers on satisfactory terms.

 

Our borrowings under our senior secured revolving credit facility expose us to interest rate risk.

 

Our earnings are exposed to interest rate risk associated with borrowings under our senior secured revolving credit facility. Our senior secured revolving credit facility carries a floating interest rate based upon short-term interest rate indices. If interest rates increase, so will our interest costs, which may have a material adverse effect on our financial condition and results of operations. We may use interest rate hedges in an effort to mitigate this risk, but those efforts may not prove successful.

 

To service our indebtedness, we require a significant amount of cash, and our ability to generate cash will depend on many factors beyond our control.

 

Our ability to make payments on and to refinance our indebtedness and to fund planned capital expenditures depends in part on our ability to generate cash in the future. This ability is, to a certain extent, subject to general economic, financial, competitive, legislative, regulatory and other factors that are beyond our control. We cannot provide assurance that we will generate sufficient cash flow from operations, that we will realize operating improvements on schedule or that future borrowings will be available to us in an amount sufficient to enable us to service and repay our indebtedness or to fund our other liquidity needs. If we are unable to satisfy our debt obligations, we may have to undertake alternative financing plans, such as:  

 

However, any alternative financing plans that we undertake, if necessary, may not allow us to meet our debt obligations.

 

We cannot provide assurance that any refinancing or debt restructuring would be possible, that any assets could be sold or that, if sold, the timing of the sales and the amount of proceeds realized from those sales would be favorable to us or that additional financing could be obtained on acceptable terms. Our inability to generate sufficient cash flows to satisfy our debt obligations, including our obligations under the 2024 Notes, or to obtain alternative financing, could materially and adversely affect our business, financial condition, results of operations and prospects.

 

Concerns over general economic, business or industry conditions may have a material adverse effect on our results of operations, liquidity and financial condition.



Concerns over global economic conditions, energy costs, geopolitical issues, inflation, the availability and cost of credit, the European, Asian and the United States financial markets have contributed to increased economic uncertainty and diminished expectations for the global economy. In addition, continued hostilities in the Middle East and the occurrence or threat of terrorist attacks in the United States or other countries could adversely affect the global economy. These factors, combined with volatility in commodity prices, business and consumer confidence and unemployment rates, have precipitated an economic slowdown. Concerns about global economic growth have had a significant adverse impact on global financial markets and commodity prices. If the economic climate in the United States or abroad deteriorates, worldwide demand for petroleum products could diminish further, which could impact the price at which we can sell our production, affect the ability of our vendors, suppliers and customers to continue operations and ultimately adversely impact our results of operations, liquidity and financial condition.



There are inherent limitations in all control systems, and misstatements due to error or fraud that could seriously harm our business may occur and not be detected.

 

Our management, including our Chief Executive Officer and Chief Financial Officer, do not expect that our internal controls and disclosure controls will prevent all possible error and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. In addition, the design of a control system must reflect the fact that there are resource constraints and the benefit of controls must be relative to their costs. Because of the inherent limitations in all control systems, an evaluation of controls can only provide reasonable assurance that all material control issues and instances of fraud, if any, in our Company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty and that breakdowns can occur because of simple error or mistake. Further, controls can be circumvented by the individual acts of some persons or by collusion of two or more persons. The design of any system of controls is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will

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succeed in achieving its stated goals under all potential future conditions. Because of inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected. A failure of our controls and procedures to detect error or fraud could seriously harm our business and results of operations.

 

Cyber-attacks targeting systems and infrastructure used by the oil and gas industry may adversely impact our operations.

 

Our business has become increasingly dependent on digital technologies to conduct certain exploration, development, production and financial activities. We depend on digital technology to estimate quantities of oil and gas reserves, process and record financial and operating data, analyze seismic and drilling information and communicate with our employees and third party partners. Unauthorized access to our seismic data, reserves information or other proprietary information could lead to data corruption, communication interruption or other operational disruptions in our exploration or production operations. Also, computers control nearly all of the oil and gas distribution systems in the United States and abroad, which are necessary to transport our production to market. A cyber-attack directed at oil and gas distribution systems could damage critical distribution and storage assets or the environment, delay or prevent delivery of production to markets and make it difficult or impossible to accurately account for production and settle transactions. While we have not experienced cyber-attacks, there is no assurance that we will not suffer such attacks and resulting losses in the future. Further, as cyber-attacks continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyber-attacks.

 

Loss of our information and computer systems could adversely affect our business.

 

We are heavily dependent on our information systems and computer based programs, including our well operations information, seismic data, electronic data processing and accounting data. If any of such programs or systems were to fail or create erroneous information in our hardware or software network infrastructure, possible consequences include our loss of communication links, inability to find, produce, process and sell oil and natural gas and inability to automatically process commercial transactions or engage in similar automated or computerized business activities. Any such consequence could have a material adverse effect on our business.

 

Certain U.S. federal income tax preferences currently available with respect to oil and natural gas production may be eliminated as a result of future legislation.

 

In past years, legislation has been proposed that would, if enacted into law, make significant changes to U.S. tax laws, including to certain key U.S. federal income tax provisions currently available to oil and gas companies. Such legislative changes have included the elimination of certain key U.S. federal income tax incentives currently available to oil and gas exploration and production. If enacted into law, these proposals would eliminate certain tax preferences applicable to taxpayers engaged in the exploration or production of natural resources. These changes include, but are not limited to (1) the repeal of the percentage depletion allowance for oil and gas properties, (2) the elimination of current deductions for intangible drilling and development costs, (3) the elimination of the deduction for U.S. production activities and (4) the increase in the amortization period from two years to seven years for geophysical costs paid or incurred in connection with the exploration for or development of, oil and natural gas within the United States. It is unclear whether any such changes will be enacted or proposed by current or future administrations or how soon any such changes would become effective. In addition, it is anticipated that the Trump administration will pass tax reform and it is possible that such legislation could negatively impact our U.S. federal income taxation. The passage of any legislation as a result of the above mentioned proposals or any other similar changes in U.S. federal income tax laws could negatively affect our financial condition and results of operations.

High Mesa, as our Class B limited partner, has the ability to take actions that conflict with the interests of other investors.

High Mesa, an affiliate of a private equity fund focused on energy and commodities, is the holder of our Class B limited partnership interest. Under our partnership agreement, the Class B limited partner has certain significant rights, including, without limitation:

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The interests of the Class B limited partner could conflict with the interests of our other investors, such as the holders of our senior notes. For example, if we encounter financial difficulties or are unable to pay our debts as they mature, the interests of the Class B limited partner may conflict with the interests of the holders of our senior notes. The Class B limited partner also may have an interest in pursuing acquisitions, divestitures, financings or other transactions that, in its judgment, could enhance its investment, even though such transactions might involve risks to our other investors.

Item 1B. Unresolved Staff Comments.

None.

Item 2. Properties

Information regarding our properties is contained in “Item 1. Business” contained herein.

Item 3. Legal Proceedings

We are party to various litigation matters arising in the ordinary course of business. We do not believe the outcome of such disputes or legal actions will have a material adverse effect on our consolidated financial statements. Accruals for losses associated with litigation are made when losses are deemed probable and can be reasonably estimated.

Litigation:  On April 13, 2005, Henry Sarpy and several other plaintiffs (collectively, “Plaintiffs”) filed a petition against Exxon, Extex, The Meridian Resource Corporation (“TMRC,” our wholly-owned subsidiary, which we acquired in 2010), and the State of Louisiana for contamination of their land in the New Sarpy and/or Good Hope Field in St. Charles Parish.  Plaintiffs claim they are owners of land upon which oil  field waste pits containing dangerous and contaminating substances are located.  Plaintiffs alleged that they discovered in May 2004 that their property is contaminated with oil field wastes greater than represented by Exxon.  The property was originally owned by Exxon and was sold to TMRC.  TMRC subsequently sold the property to Extex. We have been defending this ongoing case and investigating the scope of the Plaintiffs’ alleged damage.  On April 14, 2015, TMRC entered into a Memorandum of Understanding with Exxon to settle the claims in this ongoing matter.  On July 10, 2015, the settlement and comprised agreements were finalized and signed by the Plaintiffs and Exxon.  On July 28, 2015, the State of Louisiana issued a letter of no objection to the settlement.  As of December 31, 2016, we have accrued approximately $4.0 million ($0.8 million in current liabilities and $3.2 million in other long-term liabilities) in connection with the settlement.  The settlement requires payment over the term of six years.  

Environmental claims:  Various landowners have sued TMRC and its subsidiaries in lawsuits concerning several fields in which TMRC has historically had operations. The lawsuits seek injunctive relief and other relief, including unspecified amounts in both actual and punitive damages for alleged breaches of mineral leases and alleged failure to restore the plaintiffs’ lands from alleged contamination and otherwise from TMRC’s oil and natural gas operations. We are unable to express an opinion with respect to the likelihood of an unfavorable outcome of the various environmental claims or to estimate the amount or range of potential loss should the outcome be unfavorable. Therefore, we have not provided any amount for these claims in our financial statements at December 31, 2016.  

Due to the nature of our business, some contamination of the real estate property owned or leased by us is possible. Environmental site assessments of the property would be necessary to adequately determine remediation costs, if any.  Management revised the estimated liability for groundwater contamination in Florida based on our reassessment of our remediation costs and plan, which is pending approval by the State of Florida.  As of December 31, 2016, our revised estimated remediation liability was approximately $0.1 million.  As of December 31, 2015, we had estimated a liability of $1.3 million, based on our undiscounted engineering estimates. The obligations are included in accounts payable and accrued liabilities at December 31, 2016 and other long-term liabilities at December 31, 2015 in the accompanying consolidated balance sheets. No accrual for environmental claims has been made other than the balance noted above.

Item 4. Mine Safety Disclosures

Not applicable.

PART II

Item 5. Market For Registrant’s Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities

No class of our limited partnership interests has been registered under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), and there is no established public trading market for our equity.

As of March 30, 2017,  nine holders of our Class A and Class B limited partnership interests held 100% of such interests.

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Distributions to our partners are determined by the terms of our partnership agreement.  See also, “Item 1A. Risk Factors — High Mesa, as our Class B limited partner, has the ability to take actions that conflict with the interests of other investors.”  As of December 31, 2016, the covenants of the Company’s senior secured revolving credit facility prohibit it from making any distributions. Historically, limited distributions have been made with the approval of our Board of Directors.

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Item 6. Selected Financial Data

The following table presents our selected financial data for the periods indicated. The data have been derived from our audited consolidated financial statements for such periods. For further information that will help you better understand the summary data, you should read this financial data in conjunction with “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the consolidated financial statements and related notes and other financial information included elsewhere in this report.  The following information is not necessarily indicative of our future results.













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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis should be read in conjunction with the “Selected Financial Data” and the consolidated financial statements and related notes included elsewhere in this report. The following discussion and analysis contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, the volatility of oil and natural gas prices, production timing and volumes, estimates of proved reserves, operating costs and capital expenditures, economic and competitive conditions, regulatory changes and other uncertainties, as well as those factors discussed below and elsewhere in this report, particularly in “Risk Factors” and “Cautionary Statement Regarding Forward-Looking Statements,” all of which are difficult to predict. As a result of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur.

Overview

We have been engaged in the onshore oil and natural gas acquisition, exploitation, exploration and production business in the United States since 1987.  Currently, we are focusing on the development and acquisition of unconventional oil and natural gas reserves in the STACK.  We have transitioned our focus from our diversified asset base composed of a portfolio of conventional assets to an oil and liquids-rich resource play in the STACK with an extensive inventory of drilling opportunities.  The STACK is a prolific hydrocarbon system with high oil and liquids-rich natural gas content, multiple horizontal target horizons, extensive production history and historically high drilling success rates.  As of December 31, 2016, we have assembled a highly contiguous position of approximately 100,000 net acres largely in the up-dip, naturally-fractured oil portion of the STACK in eastern Kingfisher County, Oklahoma. As of December 31, 2016, we have over 4,000 identified gross horizontal drilling locations, over 2,000 of which we expect to operate. These drilling locations are in our primary target formations comprised of the Osage, Meramec and Oswego formations. We continue to opportunistically acquire acreage in our non-operated locations with the goal of operating wells in these locations. At present, we have six operated horizontal drilling rigs in the STACK with plans to increase to eight rigs by the end of 2017. 

The amount of revenue we generate from our operations will fluctuate based on, among other things:

In order to mitigate the impact of changes in oil, natural gas and natural gas liquid prices on our cash flows, we are a party to hedging and other price protection contracts, and we intend to enter into such transactions in the future to reduce the effect of price volatility on our cash flows.

Substantially all of our oil and natural gas activities are conducted jointly with others and, accordingly, amounts presented reflect our proportionate interest in such activities. Inflation has not had a material impact on our results of operations and is not expected to have a material impact on our consolidated results of operations in the future.

Outlook

Our revenue, profitability and future growth depend on many factors, particularly the prices of oil, natural gas and natural gas liquids, which are beyond our control. The relatively low level of natural gas prices prompted our shift in emphasis to oil and natural gas liquids over the past several years. Accordingly, the success of our business is significantly affected by the price of oil due to our current focus on development of oil reserves and exploration for oil. Oil prices are subject to significant changes. Beginning in the third quarter of 2014, the price for oil began a dramatic decline, and current prices for oil are significantly less than they have been over the last several years. Factors affecting oil prices include worldwide economic conditions, including the European credit markets; geopolitical activities, including developments in the Middle East, South America and elsewhere; worldwide supply conditions; weather conditions; actions taken by the Organization of Petroleum Exporting Countries; and the value of the U.S. dollar in international currency markets. Sustained low prices for oil, natural gas and natural gas liquids could have a material adverse effect on our financial condition, the carrying value of our oil and natural gas properties, our proved reserves and our ability to finance operations, including the amount of our borrowing base under our senior secured revolving credit facility.

Our industry has been significantly impacted by lower crude oil and natural gas prices beginning in the third quarter of 2014 with oil prices falling below $30.00 per barrel on several occasions.   The NYMEX WTI monthly settlement price averaged approximately $48.79 per Bbl in 2015 as compared to an average price of $43.32 per Bbl in 2016.  NYMEX Henry Hub monthly settlement price for natural gas averaged approximately $2.66 per MMBtu in 2015 as compared to a monthly settlement average price of $2.46 per MMBtu in 2016.  Commodity prices have improved in late 2016 with NYMEX WTI reaching $53.72 per barrel and NYMEX Henry Hub reaching $3.72 per MMBtu on December 31, 2016.  As of March 28, 2017, NYMEX WTI was $48.37 per barrel

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and NYMEX Henry Hub was $3.10 per MMBtu.    Commodity prices remain volatile and unpredictable even though commodity prices have experienced improvements in recent months.

We have increased our anticipated capital expenditures, including acquisitions, for 2017 to $290 million, which is 28% over the $226 million of capital expenditures, including acquisitions spent in 2016.  Additionally, we anticipate that up to an additional $101 million will be funded for 2017 drilling and completions activity in the STACK by BCE pursuant to our joint development agreement.  We have allocated approximately 95% of our 2017 capital expenditure to develop the STACK.  We anticipate operating up to eight drilling rigs by the end of 2017, which will result in drilling a total of approximately 150 gross wells in the STACK. Of the total anticipated gross wells to be drilled in 2017, we plan to drill approximately 42 gross wells as part of our joint development agreement with BCE.

Our derivative contracts are reported at fair value on our consolidated balance sheets and are highly sensitive to changes in the price of oil and natural gas. Changes in these derivative assets and liabilities are reported in our consolidated statement of operations as gain / loss on derivative contracts which include both the non-cash increase or decrease in the fair value of derivative contracts, as well as the effect of cash settlements of derivative contracts during the period. In 2016, we recognized a net loss on our derivative contracts of $40.5 million, which includes $88.7 million in cash settlements received for derivative contracts. The objective of our hedging program is that, over time, the combination of settlement gains and losses from derivative contracts with ordinary oil and natural gas revenues will produce relative revenue stability. However, in the short term, both settlements and fair value changes in our derivative contracts can significantly impact our results of operations, and we expect these gains and losses to continue to reflect changes in oil and natural gas prices.

We have hedged approximately 63% of our forecasted production of proved developed producing reserves through 2019 at weighted average annual floor prices ranging from $3.06 per MMBtu to $4.50 per MMBtu for natural gas and $47.68 per Bbl to $50.00 per Bbl for oil.  If oil and/or natural gas prices continue to decline for an extended period of time, we may be unable to replace expiring hedge contracts or enter new contracts for additional oil and natural gas production at favorable prices.

Depressed oil and natural gas prices have impacted our earnings by necessitating impairment write-downs in some of our  properties, either directly by decreasing the market values of the properties, or indirectly, by lowering rates of return on oil and natural gas development projects and increasing the chance of impairment write-downs.  We recorded non-cash impairment expenses of $16.3 million and $176.8 million during the years ended December 31, 2016 and 2015, respectively.  The 2016 write-downs were primarily due to downward revisions in proved reserves in some fields and decreased prices for oil, natural gas and natural gas liquids.  Our impairments were primarily related to our oil and gas properties.  For further information, see “Results of Operations: Year Ended December 31, 2016 v. Year Ended December 31, 2015:  Impairment Expense.”

The primary factors affecting our production levels are capital availability, the effectiveness and efficiency of our production operations, the success of our drilling program and our inventory of drilling prospects. In addition, we face the challenge of natural production declines. We attempt to overcome this natural decline primarily through development of our existing undeveloped reserves, enhanced completions and well recompletions, and other enhanced recovery methods. Our future growth will depend on our ability to continue to add reserves in excess of production. Our ability to add reserves through drilling and other development techniques is dependent on our capital resources and can be limited by many factors, including our ability to timely obtain drilling permits and regulatory approvals. Any delays in drilling, completing or connecting our new wells to gathering lines will negatively affect our production, which will have an adverse effect on our revenues and, as a result, cash flow from operations.

Recent Activity



Contribution from Class B limited partner and repayment of senior secured term loan facility



On November 10, 2016, High Mesa contributed $300 million in cash from the Bayou City investment to us, and we repaid all amounts outstanding under our senior secured term loan facility with such proceeds and paid down amounts owed under our senior secured revolving credit facility.



Repurchase and Redemption of 9.625% Senior Notes due 2018

On November 30, 2016, we commenced a tender offer for any and all outstanding 9.625% senior unsecured notes due 2018 (the “2018 Notes”).  The tender offer expired on December 7, 2016 and on December 8, 2016 we made payment of the aggregate principal amount of the 2018 Notes validly tendered.  In connection therewith, we caused to be deposited, with Wells Fargo Bank, National Association, the trustee for the 2018 Notes (the “Trustee”), funds sufficient to redeem any 2018 Notes that remained outstanding on December 8, 2016. On December 20, 2016, the Trustee executed a satisfaction and discharge (the “Satisfaction and Discharge”) of the indenture relating to the 2018 Notes.   The Satisfaction and Discharge, among other things, discharged the indenture and our obligations thereunder.  As a result of the tender offer and redemption, we repurchased and redeemed our $450 

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million outstanding 2018 Notes for an aggregate cost of $459.4 million, including accrued interest and fees, for the year ended December 31, 2016. 



Issuance of 7.875% Senior Notes due 2024



On December 8, 2016, we and our wholly owned subsidiary Alta Mesa Finances Services Corp., issued $500.0 million in aggregate principal amount of  7.875% senior unsecured notes due December 15, 2024 at par, the 2024 Notes, which resulted in aggregate net proceeds to us of $491.3 million, after deducting commission offering expenses.  We used the proceeds from the issuance of the 2024 Notes to fund the repurchase of the 2018 Notes pursuant to a tender offer and the redemption of any of the 2018 Notes that remained outstanding after consummation of the tender offer.  The remainder of the proceeds were used to repay a portion of our indebtedness under our senior secured revolving credit facility.



Bayou City Joint Development Agreement

 

In January 2016, we entered into a joint development agreement with BCE, a fund advised by Bayou City, to fund a portion of our drilling operations and to allow us to accelerate development of our STACK acreage. On December 31, 2016, High Mesa purchased from BCE and contributed interests in 24 producing wells, the Contributed Wells drilled under the joint development agreement to us. The drilling program will fund the development of 80 additional wells, in four tranches of 20 wells each. As of December 31, 2016, 20 additional joint wells have been drilled or spudded leaving 60 joint wells to be drilled under the joint development agreement.

 

Under the joint development agreement, BCE has committed to fund 100% of our working interest share up to a maximum of an average of $3.2 million in drilling and completion costs per well for any tranche. We are responsible for any drilling and completion costs exceeding this aggregate limit. In exchange for the payment of drilling and completion costs, BCE receives 80% of our working interest the BCE Interest in each wellbore, which the BCE Interest will be reduced to 20% of our initial working interest upon BCE achieving a 15% internal rate of return on the wells within in a tranche and automatically further reduced to 12.5% of our initial interest upon BCE achieving a 25% internal rate of return. Following the completion of each joint well, we and BCE will each bear our respective proportionate working interest share of all subsequent costs and expenses related to such joint well.



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Results of Operations: Year Ended December 31, 2016 v. Year Ended December 31, 2015



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Revenues

Oil revenues for the year ended December 31, 2016 decreased $36.1 million, or 18%, to $163.7 million in 2016 from $199.8 million in 2015. The decrease in oil revenue was primarily attributable to lower prices as well as decreased production volumes. The average price of oil exclusive of settlements of derivative contracts decreased 14% in 2016 resulting in a decrease in oil revenues of approximately $26.5 million.  The average price inclusive of settlements of derivative contracts decreased 9% from $67.73 per Bbl in 2015 to $61.53 per Bbl in 2016.  A decrease in production of 202 MBbls, or 5% resulted in an approximate $9.6 million decrease in oil revenues. The decrease in oil volumes is primarily due to the sale of the remainder of our Eagleville properties in the third quarter of 2015 of 430 MBbls and natural production decline at the Weeks Island Area of 293 MBbls.  This decrease was partially offset by new production from the STACK, which increased 564 MBbls, from 2,006 MBbls in 2015 to 2,570 MBbls in 2016.

Natural gas revenues for the year ended December 31, 2016 increased $0.3 million, or 1%, to $30.9 million in 2016 from $30.6 million in 2015. The increase in natural gas revenue was attributable to increased production volumes partially offset by lower prices during 2016.  An increase in production of 2.1 Bcf, or 17% resulted in an increase in natural gas revenues of approximately $5.3 million in 2016 as compared to 2015.  The increase in natural gas volumes is attributable to new production from the STACK, which increased 3.9 Bcfe, from 4.3 Bcfe in 2015 to 8.2 Bcfe in 2016.  This increase was partially offset by natural production decline at the Weeks Island Area of 825 MMcf and the sale of the remainder of our Eagleville properties in the third quarter of 2015 of 415 MMcf.  The average price of natural gas exclusive of settlements of derivative contracts decreased 14% in 2016 resulting in a decrease in natural gas revenues of approximately $5.0 million.  The average price inclusive of settlements of derivative contracts decreased 40% from $4.43 per Mcf in 2015 to $2.68 per Mcf in 2016. 

Natural gas liquids revenues for the year ended December 31, 2016 increased $4.8 million, or 44% to $15.7 million in 2016 from $10.9 million in 2015.  The increase in natural gas liquids revenue was primarily attributable to increased volumes as well as an increase in prices.  An increase in volumes of 278 MBbls or 41% resulted in an increase in natural gas liquids revenue of $4.4 million in 2016 as compared to 2015.  The increase in natural gas liquid volumes is due primarily to an increase in output in the STACK, which increased 324 MBbls, from 499 MBbls in 2015 to 823 MBbls in 2016.  This increase was partially offset by lower volumes due to the sale of the remainder of our Eagleville properties in the third quarter of 2015 of 84 MBbls.  The average price of natural gas liquids exclusive of settlements of derivative contracts increased 2%, from $16.01 per Bbl in 2015 to $16.38 per Bbl in 2016 resulting in an increase in natural gas liquids revenue of $0.4 million. 

Other revenues were $0.4 million during 2016 as compared to $0.7 million during 2015. The decrease is partially the result of a decrease in income from gas processing fees, as well as a decrease in pipeline revenue.

Gain on sale of assets was a gain of $3.5 million in 2016 as compared to a gain of $67.8 million in 2015. The sale of South Louisiana properties in 2016 resulted in a gain of $3.5 million.  The sale of our remaining Eagleville properties in the third quarter of 2015 resulted in a gain of $67.6 million. 

Gain (loss) on derivative contracts was a loss of $40.5 million inclusive of derivative settlements received of $88.7 million in 2016 as compared to a gain of $124.1 million inclusive of derivative settlements received of $106.9 million in 2015. The significant fluctuation from period to period is due to the volatility of oil and natural gas prices and changes in our outstanding hedge contracts during these periods.

Expenses

Lease and plant operating expense decreased $10.8 million to $56.9 million, or 16% in 2016 as compared to $67.7 million in 2015. The decrease is primarily due to lower salt water disposal costs, and a decrease in repairs, maintenance, and field services, totaling $10.3 million.  On a per unit basis, lease and plant operating expense decreased 21% from $9.86 to $7.81 per BOE for 2015 and 2016, respectively.    

Marketing and transportation expense increased $9.3 million to $13.3 million in 2016 as compared to $4.0 million in 2015.  The increase is primarily in the STACK due to increased throughput at the KFM processing facility beginning in the second quarter of 2016.  In addition, the increase is due to a higher marketing and transportation fee charged for utilizing a more efficient facility at the KFM plant.  On a per unit basis, marketing and transportation expense increased from $0.59 to $1.83 per BOE for 2015 and 2016, respectively.

Production and ad valorem taxes decreased $4.4 million to $10.7 million, or 29%, for 2016, as compared to $15.1 million for 2015.  Production taxes decreased $4.3 million primarily due to the decrease in oil revenues.  Ad valorem taxes decreased $0.1 million.  On a per unit basis, the production and ad valorem taxes decreased from $2.20 to $1.48 per BOE for 2015 and 2016, respectively.

Workover expense decreased $1.8 million to $4.7 million from $6.5 million for 2016 and 2015, respectively. This expense varies depending on activities in the field and is attributable to many different properties.

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Exploration expense includes the costs of our geology department, costs of geological and geophysical data, delay rentals, expired leases, and dry holes. Exploration expense decreased $17.9 million to $24.8 million in 2016 from $42.7 million in 2015. The decrease in exploration expense is primarily due to decreases in dry hole expense of $22.3 million, partially offset by an increase in expired leasehold of $4.6 million. As of December 31, 2016, our property, plant, and equipment balance includes $2.1 million in exploratory well costs which are deferred, pending determination of proved reserves.  Such costs will be charged to exploration expense if the wells are ultimately classified as dry holes. 

Depreciation, depletion and amortization decreased $51.1 million to $92.9 million for 2016 as compared to $144.0 million for 2015. On a per unit basis, this expense decreased 39% from $20.97 to $12.75 per BOE for 2015 and 2016, respectively. The rate is a function of capitalized costs of proved properties, proved reserves and production by field.

Impairment expense decreased  $160.5 million to $16.3 million in 2016 from $176.8 million in 2015. This non-cash expense varies with the results of exploratory and development drilling, as well as with well performance and price declines which may render some projects uneconomic, resulting in impairment. See “Critical Accounting Policies and Estimates — Impairment” below for more details related to impairment. Certain developed fields were impaired due to downward revisions in reserves based on lower commodity prices, performance or development drilling results that were below expectations.  The impairments in 2016 were primarily due to write-downs in developed fields, most notably in the Northwest, East Texas and South Louisiana, totaling $15.4 million. The impairments in 2015 were primarily due to write-downs of both unproved oil and gas costs and developed fields, primarily the Weeks Island Area, the STACK, East Texas and South Louisiana, totaling $167.8 million.

Accretion expense is related to our obligation for retirement of oil and natural gas wells and facilities. We record these liabilities when we place the assets in service, using discounted present values of the estimated future obligation. We then record accretion of the liabilities as they approach maturity. Accretion expense was $2.2 million and $2.1 million in 2016 and 2015, respectively.

General and administrative expense decreased  $2.7 million to $41.8 million in 2016 from $44.5 million in 2015. The decrease is primarily due to lower litigation settlement expenses recorded in 2016 as compared to 2015 of $5.3 million, partially offset by an increase in salaries, benefits and deferred compensation of $2.6 million in 2016.  On a per unit basis, general and administrative expenses decreased 12% from $6.48 to $5.73 per BOE for 2015 and 2016, respectively.

Interest expense, net decreased  $1.8 million to $60.0 million in 2016 from $61.8 million in 2015. The decrease was primarily due to the tender and redemption of the 2018 Notes during the fourth quarter of 2016, which decreased interest costs.  These decreases were partially offset by an increase in interest expense related to our senior secured revolving credit facility and senior term loan facility.  The senior term loan facility was repaid in full during the fourth quarter of 2016. Interest expense incurred on our borrowings under our senior secured revolving credit facility increased $1.4 million due to an increase in average outstanding balance.  Interest expense incurred on our borrowing under senior secured term loan facility increased $3.0 million as we recognized almost a full year of interest expense and additional amortized deferred financing costs of $0.3 million as compared to prior year.  We entered into the senior secured term loan facility during the second quarter of 2015.

Loss on Extinguishment of Debt was $18.2 million in 2016.  During the fourth quarter of 2016, we repurchased an aggregate principal amount of our $450 million outstanding 2018 Notes for an aggregate cost of $459.4 million, including accrued interest and fees. We recognized a loss related to the repurchase of $13.5 million, which included unamortized discount and unamortized deferred financing costs write-offs of $4.1 million.  In addition, we repaid all amounts outstanding under the senior secured term loan facility of $127.7 million, which includes accrued interest and a prepayment premium of $2.5 million.  We recognized a loss related to the repayment of $4.7 million, which included unamortized deferred financing costs write-offs of $2.0 million.

   

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Results of Operations: Year Ended December 31, 2015 v. Year Ended December 31, 2014

 

 

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Revenues 

Oil revenues for the year ended December 31, 2015 decreased $148.0 million, or 43%, to $199.8 million from $347.8 million for 2014. The decrease in revenue was attributable to lower average prices partially offset by increased production volumes. The average price of oil exclusive of settlements of derivative contracts decreased 48% in 2015; the overall price including settlements of derivative contracts decreased 27% from $93.38 per Bbl in 2014 to $67.73 per Bbl in 2015 resulting in a decrease in oil revenues of approximately $188.0 million, partially offset by an increase in production of 433 MBbls, or 11% resulting in an approximately $40.0 million increase in oil revenues. This increase is primarily due to new production from the STACK, which increased 934 MBbls, from 1,072 MBbls in 2014 to 2,006 MBbls in 2015, partially offset by lower sales volume due to the sale of the remainder of our Eagleville properties in the third quarter of 2015 and natural production decline at Weeks Island Area.  Production from our Eagleville field decreased 383 MBbls from 815 MBbls in 2014 to 432 MBbls in 2015, and our Weeks Island Area decreased 61 MBbls from 1,505 MBbls in 2014 to 1,444 MBbls in 2015.  

Natural gas revenues for the year ended December 31, 2015 decreased $34.4 million, or 53%, to $30.6 million from $65 million for 2014. The decrease in natural gas revenue was attributable to lower average prices during 2015 as well as decreased production volumes.  The average price of natural gas exclusive of settlements of derivative contracts decreased 43% in 2015 resulting in a decrease in natural gas revenues of approximately $22.9 million.  The overall price including settlements of derivative contracts decreased 9% from $4.87 per Mcf in 2014 to $4.43 per Mcf in 2015.  A decrease in production of 2.5 Bcf, or 18% resulted in a decrease in natural gas revenues of approximately $11.5 million in 2015 compared to 2014.  The decline is due to an emphasis on liquids-rich assets in our capital spending. The decrease in production is attributable to the sale of our remaining working interests in the Hilltop field in the third quarter of 2014.  The Hilltop field produced 2.8 Bcf in 2014.  In addition, production decreased 3.8 Bcf in East Texas and 0.6 Bcf in South Texas, partially offset by an increase in production in the STACK of 2.2 Bcf.

Natural gas liquids revenues decreased during 2015 to $10.9 million from $18.3 million for 2014.  Our average price decreased by 53%, from $34.04 per Bbl in 2014 to $16.01 per Bbl in 2015, partially offset by a 26% increase in volumes from 537 MBbls in 2014 to 678 MBbls in 2015.  The decline in prices is due to increased supply of natural gas liquids as a result of increased liquids-targeted drilling. The increase in volume is due primarily to an increase in production in the STACK during 2015 of 184 MBbls, partially offset by lower sales volumes due to the sale of the remainder of our Eagleville properties in the third quarter of 2015.

Other revenues were $0.7 million during 2015 as compared to $1.0 million during 2014. The decrease is partially the result of a decrease in income from gas processing fees, as well as a decrease in pipeline revenue.

Gain on sale of assets was a gain of $67.8 million in 2015 as compared to a gain of $87.5 million in 2014.  The divestiture of our remaining Eagleville properties in 2015 resulted in a gain of $67.6 million.  The divestiture of a portion of our oil and gas properties in Eagleville field and the divestiture of the remainder of our Hilltop Field properties during 2014 resulted in a gain of $72.5 million and $15.9 million, respectively.

Gain on derivative contracts was a gain of $124.1 million for 2015 as compared to a gain of $96.6 million for 2014. The significant fluctuation from period to period is due to the volatility of oil and natural gas prices and changes in our outstanding hedging contracts during these periods.

Expenses

Lease and plant operating expense increased $3.0 million to $67.7 million in 2015 as compared to $64.7 million in 2014. On a per unit basis, lease and plant operating expense increased 2% from $9.63 to $9.86 per BOE for 2014 and 2015, respectively. The increase is primarily due to higher field services,  rental equipment, and compression expense, totaling $6.9 million.  The increase was partially offset by a decrease in chemical and fuel usage and salt water disposal of $3.7 million.

Marketing and transportation expense decreased $5.1 million to $4.0 million in 2015 from $9.1 million in 2014.  The decrease is primarily due to the divestiture of a portion of our oil and gas properties in Eagleville field and the divestiture of the remainder of our Hilltop Field properties during 2014.  Hilltop Field properties produced primarily dry gas.  On a per unit basis, marketing and transportation expense decreased 57% from $1.36 to $0.59 per BOE for 2014 and 2015, respectively. 

Production and ad valorem taxes decreased $13.1 million to $15.1 million, or 46%, for 2015, as compared to $28.2 million for 2014.  Production taxes decreased $11.6 million primarily due to the decrease in oil and natural gas revenues.  Ad valorem taxes decreased $1.5 million primarily due to the sale of the remainder of our Eagleville properties in the third quarter of 2015 and the sale of our Hilltop field in the third quarter of 2014.  On a per unit basis, the production and ad valorem taxes decreased 48% from $4.20 to $2.20 per BOE for 2014 and 2015, respectively.

Workover expense decreased $2.5 million to $6.5 million from $9.0 million for 2015 and 2014, respectively. This expense varies depending on activities in the field and is attributable to many different properties.

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Exploration expense includes the costs of our geology department, costs of geological and geophysical data, delay rentals, expired leases, and dry holes. Exploration expense decreased $19.2 million to $42.7 million for 2015 from $61.9 million for 2014. The decrease in exploration expense is primarily due to decreases in G&G seismic expenditures of $11.7 million, dry hole expense of $7.6 million and plug and abandonment expenditures of $2.2 million, partially offset by an increase in delay rentals and expired leasehold of $2.2 million. As of December 31, 2015, our property, plant, and equipment balance includes $6.0 million in exploratory well costs which are deferred, pending determination of proved reserves.  Such costs will be charged to exploration expense if the wells are ultimately classified as dry holes. 

Depreciation, depletion and amortization increased $2.2 million to $144.0 million for 2015 as compared to an expense of $141.8 million for 2014. On a per unit basis, this expense decreased 1% from $21.12 to $20.97 per BOE for 2014 and 2015, respectively. The rate is a function of capitalized costs of proved properties, proved reserves and production by field.

Impairment expense increased $101.9 million to $176.8 million in 2015 from $74.9 million in 2014. This non-cash expense varies with the results of exploratory and development drilling, as well as with well performance and price declines which may render some projects uneconomic, resulting in impairment. See “Critical Accounting Policies and Estimates — Impairment” below for more details related to impairment. The increase in impairment expense is primarily due to a 47% decrease in the twelve month weighted average price for oil and a 41% decrease in the twelve month weighted average price for natural gas at December 31, 2015. The impairments in 2015 were primarily due to write-downs of both unproved oil and gas costs and developed fields.  The primary prospects impaired were in South Texas of approximately $4.1 million and Weeks Island Area of approximately $0.6 million. Several developed fields were impaired due to downward revisions in reserves based on lower commodity prices, performance or development drilling results that were below expectations.  The most significant of these were in Weeks Island Area of $129.1 million, the STACK of $15.7 million, South Louisiana of $9.4 million and East Texas of $8.9 million. 

Accretion expense is related to our obligation for retirement of oil and natural gas wells and facilities. We record these liabilities when we place the assets in service, using discounted present values of the estimated future obligation. We then record accretion of the liabilities as they approach maturity. Accretion expense was $2.1 million and $2.2 million in 2015 and 2014, respectively.

General and administrative expense decreased $24.7 million to $44.5 million in 2015 from $69.2 million in 2014. The decrease is primarily due to non-recurring capital restructuring expenditures of $13.9 million in 2014, as well as a bonus accrual reduction of $9.9 million and a decrease in deferred compensation expense of $1.8 million in 2015.  This decrease was partially offset by an increase in accrued settlement expense of $2.6 million.  On a per unit basis, general and administrative expenses decreased 37% from $10.30 to $6.48 per BOE for 2014 and 2015, respectively.

Interest expense, net increased $6.0 million to $61.8 million in 2015 from $55.8 million in 2014.  This increase is primarily due to incurred interest expense of $6.2 million and amortization of deferred financing costs of $0.5 million, related to the senior secured term loan facility that we entered into during 2015.  The increase in interest expense was partially offset by an increase in interest income of $0.7 million and lower interest expense of $0.1 million on our senior secured revolving credit facility due to a lower average balance outstanding. 

Liquidity and Capital Resources

Our principal requirements for capital are to fund our day-to-day operations, our exploration and development activities, and to satisfy our contractual obligations, primarily for the payment of debt interest and any amounts owed during the period related to our hedging positions.

Our 2016 capital budget was primarily focused on the development of our STACK and Weeks Island Area properties through exploitation and development.  We spent approximately $226 million in 2016 for exploration and development, including acquisitions, of which over 90% was allocated to our STACK operations and the Weeks Island Areas. The revised capital expenditures for 2016 reflected our plans to drill wells that were funded through the joint development agreement with BCE for the remainder of the year. We reduced our capital expenditures for 2016 from 2015 levels in response to the continued depressed oil prices and to preserve liquidity. Our future drilling plans, plans of our drilling operators and capital budgets are subject to change based upon various factors, some of which are beyond our control, including drilling results, oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, actions of our operators, gathering system and pipeline transportation constraints and regulatory approvals. A deferral of planned capital expenditures, particularly with respect to drilling and completing new wells, could result in a reduction in anticipated production, revenues and cash flows. Additionally, if we curtail our drilling program, we may lose a portion of our acreage through lease expirations.  However, because a large percentage of our acreage is held by production, we have the ability to materially increase or decrease our drilling and recompletion budget in response to market conditions with decreased risk of losing significant acreage.  In addition, we may be required to reclassify some portion of our reserves currently booked as proved undeveloped reserves to no longer be proved reserves if such a deferral of planned capital expenditures means we will be unable to develop such reserves within five years of their initial booking.

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We funded our 2016 capital expenditures predominantly with cash flows from operations, drilling and completion of capital funded through our joint development agreement with BCE and capital contributions from our Class B limited partner, supplemented by borrowings under our senior secured revolving credit facility and the issuance of the 2024 Notes. In connection with the final sale of preferred stock to Bayou City in October 2016,  High Mesa contributed $300 million from the Bayou City investment to us. In November 2016, we repaid all amounts outstanding under our senior secured term loan facility with such proceeds and paid down amounts owed under our senior secured revolving credit facility, providing us with additional liquidity.

We expect to fund our 2017 capital budget predominantly with cash flows from operations, drilling and completion capital funded through our joint development agreement with BCE, and borrowings under our senior secured revolving credit facility.  If necessary, we may also access capital through proceeds from potential asset dispositions and the future issuances of debt and/or equity securities, subject to the distribution of proceeds therefrom as set forth in our partnership agreement. We strive to maintain financial flexibility and may access capital markets as necessary to facilitate drilling on our large undeveloped acreage position and permit us to selectively expand our acreage position. In the event our cash flows are materially less than anticipated and other sources of capital we historically have utilized are not available on acceptable terms, we may curtail our capital spending.

As we execute our business strategy, we will continually monitor the capital resources available to meet future financial obligations and planned capital expenditures.  We believe our cash flows provided by operating activities, cash on hand and availability under our senior secured revolving credit facility will provide us with the financial flexibility and wherewithal to meet our cash requirements, including normal operating needs, and pursue our currently planned 2017 development drilling activities.  However, future cash flows are subject to a number of variables, including the level of oil and natural gas production and prices, and significant additional capital expenditures will be required to more fully develop our properties and acquire additional properties.  We cannot assure you that operations and other needed capital will be available on acceptable terms, or at all. 

Senior Notes

On November 30, 2016, we commenced a tender offer for any and all outstanding 2018 Notes. The tender offer expired on December 7, 2016, and on December 8, 2016 we made payment of the aggregate principal amount of the 2018 Notes validly tendered.  In connection therewith, we caused to be deposited, with Wells Fargo Bank, National Association, the trustee for the 2018 Notes, the Trustee, funds sufficient to redeem any 2018 Notes that remained outstanding on December 8, 2016.  On December 20, 2016, the Trustee executed a satisfaction and discharge, the Satisfaction and Discharge, of the indenture relating to the 2018 Notes.  The Satisfaction and Discharge, among other things, discharged the indenture and our obligations of the Company thereunder. 

 

On December 8, 2016, we and our wholly owned subsidiary Alta Mesa Finance Services Corp. (collectively, the “Issuers”) issued $500 million in aggregate principal amount of the 2024 Notes to Wells Fargo Securities, LLC and other initial purchasers for resale to certain qualified institutional buyers pursuant to Rule 144A under the Securities Act, and to eligible purchasers outside of the United States pursuant to Regulation S under the Securities Act.

 

Our net proceeds, after deducting offering expenses, were approximately $491 million. We used the net proceeds of the offering as follows:

 



The 2024 Notes are fully and unconditionally guaranteed on a senior unsecured basis by our subsidiaries (the “Subsidiary Guarantors”), and will be guaranteed by our future domestic restricted subsidiaries, other than certain immaterial subsidiaries. The terms of the 2024 Notes are governed by the indenture, dated as of December 8, 2016 (the “Indenture”), by and among the Issuers, the Subsidiary Guarantors and U.S. Bank, N.A., as trustee.

 

The 2024 Notes will mature on December 15, 2024, and interest is payable semi-annually on June 15 and December 15 of each year, beginning June 15, 2017. At any time prior to December 15, 2019, we may, from time to time, redeem up to 35% of the aggregate principal amount of the 2024 Notes in an amount of cash not greater than the net cash proceeds from certain equity offerings at the redemption price of 107.875% of the principal amount, plus accrued and unpaid interest, if any, to the date of redemption, if at least 65% of the aggregate principal amount of the 2024 Notes remains outstanding after such redemption and the redemption occurs within 120 days of the closing date of such equity offering. At any time prior to December 15, 2019, we may, on any one or more occasions, redeem all or part of the 2024 Notes for cash at a redemption price equal to 100% of their principal amount of the 2024 Notes redeemed plus an applicable make-whole premium and accrued and unpaid interest, if any, to the date of redemption. Upon the

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occurrence of certain kinds of change of control, each holder of the 2024 Notes may require us to repurchase all or a portion of the 2024 Notes for cash at a price equal to 101% of the aggregate principal amount of the 2024 Notes, plus accrued and unpaid interest, if any, to the date of repurchase. On and after December 15, 2019, we may redeem the 2024 Notes, in whole or in part, at redemption prices (expressed as percentages of principal amount) equal to 105.906% for the twelve-month period beginning on December 15, 2019, 103.938% for the twelve-month period beginning December 15, 2020, 101.969% for the twelve-month period beginning on December 15, 2021 and 100.000% beginning on December 15, 2022, plus accrued and unpaid interest, if any, to the date of redemption.

 

The 2024 Notes and the related guarantees are the Issuers’ and the Subsidiary Guarantors’ unsecured, senior obligations. Accordingly, they will rank equal in right of payment to all of our existing and future senior indebtedness; senior in right of payment to all of our existing and future indebtedness that is expressly subordinated to the 2024 Notes or the respective guarantees; effectively subordinated to all of our existing and future secured indebtedness to the extent of the value of the collateral securing such indebtedness, including amounts outstanding under our senior secured revolving credit facility; and structurally subordinated to all existing and future indebtedness and obligations of any of our subsidiaries that do not guarantee the 2024 Notes.

 

The Indenture contains certain covenants limiting the Issuers’ ability and the ability of the restricted subsidiaries to, under certain circumstances, prepay subordinated indebtedness, pay distributions, redeem stock or make certain restricted investments; incur indebtedness; create liens on the Issuers’ assets to secure debt; restrict dividends, distributions or other payments; enter into transactions with affiliates; designate subsidiaries as unrestricted subsidiaries; sell or otherwise transfer or dispose of assets, including equity interests of restricted subsidiaries; effect a consolidation or merger; and change our line of business.

 

The Indenture contains customary events of default, including:  

Senior Secured Revolving Credit Facility

We have a $750 million senior secured revolving credit facility currently subject to a $287.5 million borrowing base limit with Wells Fargo Bank, National Association as the administrative agent. Our senior secured revolving credit facility does not permit us to borrow funds if at the time of such borrowing, after giving pro forma effect to the application of funds from the borrowing, we have in deposit accounts available cash in excess of $25 million. Our senior secured revolving credit facility also does not permit us to borrow funds if at the time of such borrowing we are not in pro forma compliance with our financial covenants.

 

As of March 30, 2017, we have borrowed $95.7 million under the senior secured revolving credit facility and have $7.6 million of outstanding letters of credit reimbursement obligations.

Principal amounts borrowed are payable on the maturity date with such borrowings bearing interest, payable quarterly. We have a choice of borrowing in Eurodollars or at the base rate. Eurodollar loans bear interest at a rate per annum equal to the rate appearing on the Reuters Reference LIBOR01 page as the London Interbank Offered Rate (“LIBOR”), for deposits in dollars at 11:00 a.m. (London, England time) for one, three, or six months plus an applicable margin ranging from 275 to 375 basis points if our leverage ratio does not exceed 3.25 to 1.00, depending on the percentage of our borrowing base utilized, and ranging from 300 to 400 basis points if our leverage ratio exceeds 3.25 to 1.00. Base rate loans bear interest at a rate per annum equal to the greatest of (i) the agent bank’s reference rate, (ii) the federal funds effective rate plus 50 basis points and (iii) the rate for one month Eurodollar loans plus 1%, plus an applicable margin ranging from 175 to 275 basis points if our leverage ratio does not exceed 3.25 to 1.00, depending on the percentage of our borrowing base utilized, and ranging from 200 to 300 basis points if our leverage ratio exceeds 3.25 to 1.00. The next scheduled redetermination of our borrowing base is on May 1, 2017. Our borrowing base may be reduced in connection with the next redetermination of our borrowing base. The amounts outstanding under our senior secured revolving credit facility are secured by first priority liens on substantially all of our oil and natural gas properties and associated assets and all of the stock of our material operating subsidiaries that are guarantors of our senior secured revolving credit facility. If an event of default occurs under our senior secured revolving credit facility, the administrative agent will have the right to proceed against the pledged capital stock and take control of substantially all of our and our material operating subsidiaries that are guarantors’ assets.

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Our senior secured revolving credit facility contains restrictive covenants that may limit our ability to, among other things, incur additional indebtedness, sell assets, guaranty or make loans to others, make investments, enter into mergers, make certain payments and distributions, enter into or be party to hedge agreements, amend our organizational documents, incur liens and engage in certain other transactions without the prior consent of the lenders. Our senior secured revolving credit facility permits us to make distributions in any fiscal quarter so long as the amount of distributions made in such fiscal quarter does not exceed our excess cash flow from the immediately preceding fiscal quarter, no event of default exists, before and after giving effect to such distribution, our pro forma leverage ratio is less than 3.00 to 1.00 and before and after giving effect to such distribution the unused commitment amounts available under our senior secured revolving credit facility is at least 20% of the commitments in effect.  As of December 31, 2016, the covenants of the Company’s senior secured revolving credit facility prohibit it from making any distributions.

 

Our senior secured revolving credit facility also requires us to maintain the following two financial ratios:

 

•a current ratio, tested quarterly, of our consolidated current assets to our consolidated current liabilities of not less than 1.0 to 1.0 as of the end of each fiscal quarter; and

 

•a leverage ratio, tested quarterly, commencing with the fiscal quarter ended December 31, 2016, of our consolidated debt (other than obligations under hedge agreements) as of the end of such fiscal quarter to our consolidated EBITDAX over the four quarter period then ended (but annualized for the fiscal quarters ending December 31, 2016, March 31, 2017, and June 30, 2017) of not greater than 4.0 to 1.0.

Cash Flows Provided by Operating Activities

Operating activities provided cash of $131.4 million in 2016, as compared to $144.0 million in 2015. The $12.6 million decrease in operating cash flows was attributable to various factors. Cash-based items of net income, including revenues (exclusive of unrealized commodity gains or losses), operating expenses and taxes, general and administrative expenses, and the cash portion of our interest expense, resulted in a net decrease of approximately $36.1 million in earnings and a negative impact on cash flow. The changes in our working capital accounts provided $27.8 million in cash as compared to having provided $4.5 million in cash in 2015.

Operating activities provided cash of $144.0 million in 2015, as compared to $184.9 million in 2014. The $40.9 million decrease in operating cash flows was attributable to various factors. Cash-based items of net income, including revenues (exclusive of unrealized commodity gains or losses), operating expenses and taxes, general and administrative expenses, and the cash portion of our interest expense, resulted in a net decrease of approximately $43.2 million in earnings and a negative impact on cash flow. The changes in our working capital accounts provided $4.5 million as compared to having provided $2.2 million in cash in 2014.

Cash Flows Used in Investing Activities

Investing activities used cash of $224.3 million for the year ended December 31, 2016 as compared to $105.8 million for the year ended December 31, 2015. The increase in cash used in investing activities was primarily related to proceeds from the sale of property in 2015 of approximately $141.4 million.  The increase in cash used for investing activities was partially offset by decreased expenditures for drilling and development and decreased acquisitions in 2016.    

Investing activities used cash of $105.8 million for the year ended December 31, 2015 as compared to $189.7 million for the year ended December 31, 2014. The decrease in cash used in investing activities was primarily related to decreased expenditures for drilling and development, partially offset by lower proceeds from the sale of assets and an increase in acquisitions.  In 2015, the sale of the remaining portion of our interest in the Eagleville field provided net proceeds of approximately $115.0 million and the acquisition of undeveloped leasehold interests in Oklahoma resulted in a use of cash of $47.4 million.  In addition, release of non-invested funds in the restricted cash account, provided cash of $24.6 million

Cash Flows Provided by Financing Activities

Financing activities provided cash of $91.2 million during 2016 as compared to cash used of $30.6 million during 2015, an increase of $121.8 million.  During 2016, we used proceeds from the issuance of the 2024 Notes of $500.0 million, capital contributions from our Class B limited partner of $303.5 million and borrowings under our senior secured revolving credit facility of $222.6 million to repay $459.4 million on the 2018 Notes, repay $127.7 million on our senior secured term loan facility and pay down $333.9 million under our senior secured revolving credit facility.  In addition, we incurred $13.7 million of deferred financing costs.

Financing activities used cash of $30.6 million during 2015 as compared to $0.4 million during 2014, an increase of $30.2 million.  During 2015, we used proceeds from the sale of our remaining interests in Eagleville properties of $115.0 million and proceeds from the issuance of our senior secured term loan facility of $121.0 million, net of issuance cost to reduce the outstanding balance under our senior secured revolving credit facility by $295.0 million.  We received $252.5 million in proceeds from long-term debt consisting of $125.0 million under our senior secured term loan facility and $127.5 million in borrowings under our senior secured revolving credit facility.  We made capital distributions of $3.8 million in 2015 as compared to a capital distribution of $0.5

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million in 2014.  We received capital contributions of $20 million from our Class B limited partner in 2015.  No contributions were received in 2014.  We incurred $4.3 million of deferred financing cost in 2015 related to the borrowing of our senior secured term loan facility.

Risk Management Activities — Commodity Derivative Instruments

Due to the risk of low oil and natural gas prices, we periodically enter into price-risk management transactions (e.g., swaps, collars, puts, calls, and financial basis swap contracts) for a portion of our oil, natural gas, and natural gas liquids production. In certain cases, this allows us to achieve a more predictable cash flow, as well as to reduce exposure from price fluctuations. The commodity derivative instruments apply to only a portion of our production, and provide only partial price protection against declines in oil, natural gas, and natural gas liquids prices, and may partially limit our potential gains from future increases in prices. At December 31, 2016, commodity derivative instruments were in place covering approximately 92% of our projected oil production, approximately 72% of our natural gas production, and approximately 11% of our natural gas liquids production from proved developed properties for 2017. See Note 7 to our consolidated financial statements as of December 31, 2016, “Derivative Financial Instruments,” for further information.

Contractual Obligations

The following table summarizes our contractual obligations as of December 31, 2016:

 



Off-Balance Sheet Arrangements

As of December 31, 2016, we had no guarantees of third-party obligations. Our off-balance sheet obligations include the obligations under operating leases, the $2.2 million contingent properties payment for properties acquired in 2008 and prior years, and the $1.5 million contingent payment if we decide to forego certain drilling activities.  We also have bonds posted in the aggregate amount of $24.0 million, primarily to cover future abandonment costs, and $7.6 million in letters of credit provided under our senior secured revolving credit facility.  We typically enter into short-term drilling contracts which are customary in the oil and gas industry.  We have no other off-balance sheet arrangements that are reasonably likely to materially affect our liquidity and capital resources.

We have no plans to enter into any additional off-balance sheet arrangements in the foreseeable future.

Critical Accounting Policies and Estimates

The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”). As used herein, the following acronyms have the following meanings: “FASB” means the Financial Accounting Standards Board; the “Codification” refers to the Accounting Standards Codification, the collected accounting and reporting guidance maintained by the

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FASB; “ASC” means Accounting Standards Codification and is generally followed by a number indicating a particular section of the Codification; and “ASU” means Accounting Standards Update, followed by an identification number, which are the periodic updates made to the Codification by the FASB.

The preparation of our consolidated financial statements requires us to make estimates and assumptions that affect our reported results of operations and the amount of reported assets, liabilities and proved oil and natural gas reserves. Some accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. Actual results may differ from the estimates and assumptions used in the preparation of our consolidated financial statements. Described below are the most significant policies we apply in preparing our consolidated financial statements, some of which are subject to alternative treatments under accounting principles generally accepted in the United States. We also describe the most significant estimates and assumptions we make in applying these policies.

Use of Estimates.  The preparation of consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period.



Reserve estimates significantly impact depreciation, depletion and amortization expense and impairments of oil and natural gas properties and are subject to change based on changes in oil and natural gas prices and trends and changes in estimated reserve quantities.  Other significant estimates include those related to oil and natural gas reserves, the value of oil and natural gas properties (including acquisition properties), oil and natural gas revenues, bad debts, asset retirement obligations, derivative contracts, state taxes and contingencies and litigation. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances. We review estimates and underlying assumptions on a regular basis.  Actual results may differ from these estimates.

Property and Equipment. Oil and natural gas producing activities are accounted for using the successful efforts method of accounting. Under the successful efforts method, lease acquisition costs and all development costs, including unsuccessful development wells, are capitalized.

Unproved Properties — Acquisition costs associated with the acquisition of leases are recorded as unproved properties and capitalized as incurred. These consist of costs incurred in obtaining a mineral interest or right in a property, such as a lease in addition to options to lease, broker fees, recording fees and other similar costs related to activities in acquiring properties. Unproved properties are classified as unproved until proved reserves are discovered, at which time related costs are transferred to proved oil and natural gas properties.

Exploration Expense — Exploration expenses, other than exploration drilling costs, are charged to expense as incurred. These expenses include seismic expenditures and other geological and geophysical costs, expired leases, and lease rentals. The costs of drilling exploratory wells and exploratory-type stratigraphic wells are initially capitalized pending determination of whether the well has discovered proved commercial reserves. If the exploratory well is determined to be unsuccessful, the cost of the well is transferred to expense. Exploratory well drilling costs may continue to be capitalized if the reserve quantity is sufficient to justify completion as a producing well and sufficient progress in assessing the reserves and the economic and operating viability of the project is being made.

Proved Oil and Natural Gas Properties — Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering, and storing oil and natural gas are capitalized. All costs incurred to drill and equip successful exploratory wells, development wells, development-type stratigraphic test wells, and service wells, including unsuccessful development wells, are capitalized.

Impairment — The capitalized costs of proved oil and natural gas properties are reviewed at least quarterly for impairment following the guidance provided in ASC 360-10-35, Property, Plant and Equipment, Subsequent Measurement, whenever events or changes in circumstances indicate that the carrying amount of a long-lived asset or asset group exceeds its fair market value and is not recoverable. The determination of recoverability is based on comparing the estimated undiscounted future net cash flows at a producing field level to the carrying value of the assets. If the future undiscounted cash flows, based on estimates of anticipated production from proved reserves and future crude oil and natural gas prices and operating costs, are lower than the carrying cost, the carrying cost of the asset or group of assets is reduced to fair value. For our proved oil and natural gas properties, we estimate fair value by discounting the projected future cash flows at an appropriate risk-adjusted discount rate.

Unproved properties are assessed at least annually to determine whether they have been impaired. Individually significant properties are assessed for impairment on a property-by-property basis, while individually insignificant unproved leasehold costs may be assessed in the aggregate. If unproved leasehold costs are found to be impaired, an impairment allowance is provided and a loss is recognized in the consolidated statement of operations.

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Depreciation, Depletion and Amortization — Depreciation, depletion and amortization (“DD&A”) of capitalized costs of proved oil and natural gas properties is computed using the unit-of-production method based upon estimated proved reserves. Assets are grouped for DD&A on the basis of reasonable aggregation of properties with a common geological structural feature or stratigraphic condition, such as a reservoir or field. The reserve base used to calculate DD&A for leasehold acquisition costs and the cost to acquire proved properties is the sum of proved developed reserves and proved undeveloped reserves. The reserve base used to calculate DD&A for lease and well equipment costs, which include development costs and successful exploration drilling costs, includes only proved developed reserves.

Revenue Recognition. We recognize oil, natural gas and natural gas liquids revenues when products are delivered at a fixed or determinable price, title has transferred and collectability is reasonably assured. We use the sales method of accounting for recognition of natural gas imbalances.

Derivative Financial Instruments. We use derivative contracts to hedge the effects of fluctuations in the prices of oil, natural gas and natural gas liquids. We account for such derivative instruments in accordance with ASC 815, “Derivatives and Hedging,” which establishes accounting and disclosure requirements for derivative instruments and requires them to be measured at fair value and recorded as assets or liabilities in the consolidated balance sheets (see Note 6 for information on fair value).

Under ASC 815, hedge accounting is used to defer recognition of unrealized changes in the fair value of such financial instruments, for those contracts which qualify as fair value or cash flow hedges, as defined in the guidance. Historically, we have not designated any of our derivative contracts as fair value or cash flow hedges. Accordingly, the changes in fair value of the contracts are included in earnings as “Gain (loss) on derivative contracts.”  Cash flows from settlements of derivative contracts are classified as operating cash flows.

Income Taxes. We have elected under the Internal Revenue Code provisions to be treated as individual partnerships for tax purposes. Accordingly, items of income, expense, gains and losses flow through to the partners and are taxed at the partner level. Accordingly, no tax provision for federal operations taxes is included in the consolidated financial statements.

We are subject to the Texas margin tax, which is considered a state income tax, and is included in “Provision for state income tax” on the consolidated statement of operations. We record state income tax (current and deferred) based on taxable income as defined under the rules for the margin tax.

Acquisitions. Acquisitions are accounted for as purchases using the acquisition method of accounting. Accordingly, the results of operations are included in our consolidated statements of operations from the closing date of the acquisitions. Purchase prices are allocated to acquired assets and assumed liabilities based on their estimated fair value at the time of the acquisition.

Asset Retirement Obligations. We estimate the present value of future costs of dismantlement and abandonment of our wells, facilities, and other tangible, long-lived assets, recording them as liabilities in the period incurred. We follow ASC 410, Asset Retirement and Environmental Obligations. ASC 410 requires that an asset retirement obligation (“ARO”) associated with the retirement of a tangible long-lived asset be recognized as a liability in the period in which it is incurred or becomes determinable (as defined by the standard), with an associated increase in the carrying amount of the related long-lived asset. The cost of the tangible asset, including the initially recognized asset retirement cost, is depreciated over the useful life of the asset and accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value. The fair value of the ARO is measured using expected future cash outflows for abandonment discounted generally at our cost of capital at the time of recognition.

Investments. Our investment consists of a 10.17% ownership interest in a drilling company, Orion Drilling Company, LLC (“Orion”). The investment is accounted for under the cost method and we have recorded $9.0 million of Investment in LLC on the consolidated balance sheets as of December 31, 2016 and 2015.  Under this method, our share of earnings or losses of the investment are not included in the consolidated statements of operations. Distributions from Orion are recognized in current period earnings as declared.    

Alta Mesa is a part owner of AEM with an ownership interest of less than 10%.  AEM markets our oil and natural gas and sells it under short-term contracts generally with month-to-month pricing based on published regional indices, with differentials for transportation, location, and quality taken into account. AEM remits monthly collections of these sales to us, and receives a 1% marketing fee. 

Deferred Financing Costs.  The Company capitalizes costs incurred in connection with obtaining financing. These costs are amortized over the term of the related financing using the straight-line method, which approximates the effective interest method. The amortization expense is recorded as a component of interest expense in the consolidated statement of operations.

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Recent Accounting Pronouncements

In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers.  The update provides guidance concerning the recognition, measurement and disclosure of revenue from contracts with customers.  Its objective is to increase the usefulness of information in the financial statements regarding the nature, timing and uncertainty of revenues.  ASU 2014-09 is effective for annual and interim periods beginning after December 15, 2016. The standard is required to be adopted using either the full retrospective approach, with all prior periods presented adjusted, or the modified retrospective approach, with a cumulative adjustment to retained earnings on the opening balance sheet. In August 2015, the FASB issued ASU No. 2015-14, Deferral of the Effective Date (“ASU 2015-14”).  ASU 2015-14 deferred the effective date of the new revenue standard by one year, making it effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period.  The Company has not yet selected a transition method and is currently assessing the impact on the consolidated financial statements.  The Company is continuing to evaluate the provisions of this ASU as it relates to certain sales contracts and in particular as it relates to disclosure requirements. 

In January 2016, the FASB issued ASU No. 2016-01, Recognition and Measurement of Financial Assets and Financial Liabilities, which requires that most equity instruments be measured at fair value with subsequent changes in fair value recognized in net income. ASU 2016-01 also impacts financial liabilities under the fair value option and the presentation and disclosure requirements for financial instruments. ASU 2016-01 does not apply to equity method investments or investments in consolidated subsidiaries. ASU 2016-01 is effective for fiscal years beginning after December 15, 2017, including interim periods within those years. The Company is currently evaluating the effect that adopting this guidance will have on its financial position, cash flows and results of operations.

In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842) which supersedes ASC 840 “Leases” and creates a new topic, ASC 842 “Leases.” The amendments in this update require, among other things, that lessees recognize the following for all leases (with the exception of short-term leases) at the commencement date: (1) a lease liability, which is a lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis; and (2) a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. Lessees and lessors must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. The amendments are effective for interim and annual reporting periods beginning after December 15, 2018. The Company does not plan to adopt the standard early.  The Company enters into lease agreements to support its operations. These lease agreements are for assets such as office space, vehicles, field services and equipment.  The Company continues to evaluate the impacts of the amendments to our financial statements and accounting practices for leases.

In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments, which is intended to reduce diversity in practice in how certain transactions are classified in the statements of cash flows. ASU 2016-15 is effective for fiscal years beginning after December 15, 2017, including interim periods within those years. The adoption of this guidance will not impact the Company’s financial position or results of operations but could result in presentation changes on its consolidated statements of cash flows.

In October 2016, the FASB issued ASU No. 2016-17, Consolidation: Interests Held through Related Parties That Are under Common Control. This guidance provides an amendment to the consolidation guidance on how a reporting entity that is the single decision maker of a VIE should treat indirect interests in the entity held through related parties that are under common control with the reporting entity when determining whether it is the primary beneficiary of that VIE. We have adopted this ASU and there was no current impact to our consolidated financial statements.

In November 2016, the FASB issued ASU 2016-18, Statement of Cash Flows: Restricted Cash, which requires an entity to explain the changes in the total of cash, cash equivalents, restricted cash, and restricted cash equivalents on the statements of cash flows and to provide a reconciliation of the totals in that statement to the related captions in the balance sheet when the cash, cash equivalents, restricted cash, and restricted cash equivalents are presented in more than one line item on the balance sheet. This ASU is effective for annual and interim periods beginning after December 15, 2017, and is required to be adopted using a retrospective approach, with early adoption permitted. The adoption of this guidance will not impact the Company’s financial position or results of operations but could result in presentation changes on its consolidated statements of cash flows.

In January 2017, the FASB issued ASU No. 2017-01, Clarifying the Definition of a Business, which provides guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. ASU 2017-01 requires entities to use a screen test to determine when an integrated set of assets and activities is not a business or if the integrated set of assets and activities needs to be further evaluated against the framework. ASU 2017-01 is effective for fiscal years beginning after December 15, 2017, including interim periods within those years. The Company is currently evaluating the effect that adopting this guidance will have on its financial position, cash flows and results of operations.

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Item 7A. Quantitative and Qualitative Disclosures about Market Risk

We are exposed to certain market risks that are inherent in our consolidated financial statements that arise in the normal course of business. We may enter into derivative instruments to manage or reduce market risk, but we do not enter into derivative agreements for speculative purposes.

We do not designate these derivative instruments as hedges for accounting purposes. Accordingly, the changes in the fair value of these instruments are recognized currently in earnings.

Commodity Price Risk and Hedges

Our major market risk exposure is to prices for oil, natural gas and natural gas liquids. These prices have historically been volatile. As such, future earnings are subject to change due to changes in these prices. Realized prices are primarily driven by the prevailing worldwide price for oil and regional prices for natural gas. We have used, and expect to continue to use, oil, natural gas and natural gas liquids derivative contracts to reduce our exposure to the risks of changes in the prices of oil, natural gas and natural gas liquids. Pursuant to our risk management policy, we engage in these activities as a hedging mechanism against low prices and price volatility associated with pre-existing or anticipated sales of oil, natural gas and natural gas liquids.

As of December 31, 2016, we have hedged approximately 63% of our forecasted production from proved developed reserves through 2019 at average annual floor prices ranging from $3.06 per MMBtu to $4.50 per MMBtu for natural gas and $47.68 per Bbl to $50.00 per Bbl for oil. Forecasted production from proved reserves is estimated in our December 2016 reserve report using prices, costs and other assumptions required by SEC rules. Our actual production will vary from the amounts estimated in the report, perhaps materially. Please read the disclosures under “Our estimated oil and natural gas reserve quantities and future production rates are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or the underlying assumptions will materially affect the quantities and present value of our reserves” in “Item 1A. Risk Factors” above.

The fair value of our oil and natural gas derivative contracts and basis swaps at December 31, 2016 was a net liability of $24.9 million. A 10% increase or decrease in oil and natural gas prices with all other factors held constant would result in an unrealized loss or gain, respectively, in the fair value (generally correlated to our estimated future net cash flows from such instruments) of our oil and natural gas commodity contracts of approximately $29.0 million (decrease in value) or $25.6 million (increase in value), respectively, as of December 31, 2016. 

Counterparty and Customer Credit Risk

 

Our derivative contracts expose us to credit risk in the event of nonperformance by counterparties. While we do not require counterparties to our derivative contracts to post collateral, we do evaluate the credit standing of such counterparties as we deem appropriate. The counterparties to our derivative contracts currently in place have investment grade ratings.

 

Our principal exposures to credit risk are through receivables resulting from joint interest receivables and receivables from the sale of our oil and natural gas production due to the concentration of our oil and natural gas receivables with several significant customers. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. However, we believe the credit quality of our customers is high.

 

Joint operations receivables arise from billings to entities that own partial interests in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we intend to drill. We have little ability to control whether these entities will participate in our wells.

Interest Rates

We are subject to interest rate risk on our long-term fixed interest rate debt and variable interest rate borrowings. Although in the past we have used interest rate swaps to mitigate the effect of fluctuating interest rates on interest expense, we currently have no

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open interest rate derivative contracts. A 1% increase in interest rates (100 LIBOR basis points) would increase interest expense on our variable rate debt by approximately $0.4 million, based on the balance outstanding at December 31, 2016.  

Inflation

Inflation in the United States has been relatively low in recent years and did not have a material impact on our results of operations for the years ended December 31, 2016 or 2015.  Although the impact of inflation has been insignificant in recent years, it could cause upward pressure on the cost of oilfield services, equipment and general and administrative expenses. 

Item 8. Financial Statements and Supplementary Data

The consolidated financial statements and supplementary financial information required to be filed under this item are presented beginning on page F-1 in Part IV, Item 15 of this annual report and are incorporated herein by reference.

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None.

Item 9A. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

In accordance with Exchange Act Rule 13a-15 and 15d-15, we carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and our Chief Financial Officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of December 31, 2016 to provide reasonable assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Our disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed in reports filed or submitted under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.

Management’s Annual Report on Internal Control Over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rule 13a-15(f) and 15d-15(f) under the Exchange Act. We have performed an evaluation under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of our internal control over financial reporting. Our management assessed the effectiveness of our internal control over financial reporting as of December 31, 2016. Because of its inherent limitations, internal control over financial reporting cannot provide absolute assurance of achieving financial reporting objectives. Internal control over financial reporting is a process that involves human diligence and compliance and is subject to lapses in judgment and breakdowns resulting from human failures. Internal control over financial reporting also can be circumvented by collision or improper management override. Because of such limitations, there is a risk that material misstatements may not be prevented or detected on a timely basis by internal control over financial reporting. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions or that the degree of compliance with established policies or procedures may deteriorate. 

Our management used the criteria set forth in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) to perform its assessment. Based on this assessment, our management, including our Chief Executive Officer and our Chief Financial Officer, concluded, that as of December 31, 2016, our internal control over financial reporting was effective based on those criteria.

Changes in Internal Control Over Financial Reporting

There has been no change in our internal control over financial reporting during the quarter ended December 31, 2016 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

Item 9B. Other Information

None.

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PART III

Item 10. Directors, Executive Officers, and Corporate Governance

As is the case with many partnerships, we do not directly employ officers, directors or employees. Our operations and activities are managed by the Board of Directors of our General Partner, Alta Mesa Holdings GP, LLC, and the officers and directors of Alta Mesa Services, an entity wholly owned by us. References to our directors are references to the directors of our General Partner. References to our officers and employees are references to the officers and employees of Alta Mesa Services.

All of our executive management personnel are employees of Alta Mesa Services and devote all of their time to our business and affairs. We also utilize a significant number of employees of Alta Mesa Services to operate our properties and provide us with certain general and administrative services. Under the shared services and expenses agreement with Alta Mesa Services, we reimburse Alta Mesa Services for its operational personnel who perform services for our benefit.

Board Leadership Structure

Our Chairman is Michael E. Ellis, our Chief Operating Officer and founder of the Company. Our Board of Directors has no policy regarding the separation of the positions of Chief Executive Officer and Chairman. We also do not have a lead independent director.

Board Oversight of Risk

Like all businesses, we face risks in our business activities. Many of these risks are discussed under the caption “Risk Factors” elsewhere in this report. The Board of Directors has delegated to management the primary responsibility of risk management, while it has retained oversight of management in that regard.

In addition, our Board of Directors considers our practices regarding risk assessment and risk management, reviews our contingent liabilities, reviews our oil and natural gas reserve estimation practices, as well as major legislative and regulatory developments that could affect us. Our Board reviews and attempts to mitigate risks which may result from our compensation policies.

Executive Officers and Directors

The following table sets forth the names, ages and positions of our present directors and executive officers as of December 31, 2016. Members of our Board of Directors are elected for one-year terms.

 





The following is a biographical summary of the business experience of these directors and executive officers:

Harlan H. Chappelle joined Alta Mesa as President, CEO and director in November 2004, and has led us in a period of significant growth, building a strong management and technical team, focusing us on our greatest opportunities, making strategic acquisitions, and restructuring our financing. Mr. Chappelle has over 30 years in field operations, engineering, management, marketing and trading, acquisitions and divestitures, and field re-development. He has worked for Louisiana Land & Exploration Company, Burlington Resources, Southern Company, and Mirant. Mr. Chappelle retired as a Commander from the U.S. Navy Reserve. He has a Bachelor of Chemical Engineering from Auburn University and a Master of Science in Petroleum Engineering from The University of Texas at Austin.

Michael E. Ellis founded Alta Mesa in 1987 after beginning his career with Amoco, and is our Chairman and Chief Operating Officer, as well as Vice President of Engineering. Mr. Ellis manages all day-to-day engineering and field operations of Alta Mesa. He built our asset base by starting with small earn-in exploitation projects, then progressively grew the company with successive acquisitions of fields from major oil companies, and consistent success in exploration and development drilling. He has over 30 years’

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experience in management, engineering, exploration and acquisitions and divestitures. Mr. Ellis holds a Bachelor of Science in Civil Engineering from West Virginia University.  Mr. Ellis is the spouse of Mickey Ellis, our director. 

Michael A. McCabe, our CFO as well as a Vice President, joined Alta Mesa in September 2006 and became a director in 2014. Mr. McCabe has over 25 years of corporate finance experience, with a focus on the energy industry. From 2004 until 2006, Mr. McCabe served as President and sole owner of Bridge Management Group, Inc., a private consulting firm primarily providing advisory services to us and to MultiFuels, Inc., a Houston based developer of natural gas storage facilities. He has served in senior positions with Bank of Tokyo, Bank of New England, and Key Bank. Mr. McCabe holds a Bachelor of Science in Chemistry and Physics from Bridgewater State University, a Master of Science in Chemical Engineering from Purdue University and a Master of Business Administration in Financial Management from Pace University.

David Murrell has served as our Vice President, Land and Business Development since 2006. Mr. Murrell has over 30 years of experience in Gulf Coast leasing, exploration and development programs, contract management and acquisitions and divestitures. He created a structured land management system for Alta Mesa, and built a team of division order analysts, lease analysts, landmen, and field representatives that has facilitated our growth. Mr. Murrell earned a Bachelor of Business Administration in Petroleum Land Management from the University of Oklahoma and is a Certified Professional Landman through the Association of Professional Landmen. 

Homer “Gene” Cole joined Alta Mesa in 2007 and has served in the position of Vice President and Chief Technical Officer since August 2015 and became a director in August 2015.  Mr. Cole has over 25 years of extensive domestic and international oilfield experience in management, well completions and well stimulation design and execution. He started his career with Schlumberger Dowell as a Field Engineer and served from 1986 to 2007 in numerous positions of increasing responsibility with Schlumberger in the areas of field operations, engineering and management. He has a Bachelor of Science in Petroleum Engineering from Marietta College.

Don Dimitrievich was appointed to our Board of Directors as HPS’s director nominee in March 2014. Mr. Dimitrievich is a Managing Director at HPS Investment Partners, a leading global investment firm with approximately $39 billion of assets under management.  At HPS, Mr. Dimitrievich oversees HPS’s private credit investment strategy for the energy and power sectors. HPS has invested over $4 billion in direct energy-related investments since inception in 2007. Prior to joining HPS in 2012, Mr. Dimitrievich was a Managing Director of Citi Credit Opportunities, a credit-focused principal investment group. At Citi Credit Opportunities, Mr. Dimitrievich oversaw the energy and power portfolio and invested over $800 million in mezzanine, special situation and equity co-investments, and secondary market opportunities. Mr. Dimitrievich began his career as a corporate attorney in the New York office of Skadden, Arps, Slate, Meagher & Flom LLP focusing on energy mergers and acquisitions and capital markets transactions.  Mr. Dimitrievich also serves on the board of Energy & Exploration Partners, Inc. Mr. Dimitrievich has a Law degree with Great Distinction from McGill University in Montreal, Canada and earned a Chemical Engineering degree with Great Distinction from Queen’s University in Kingston, Canada.    

William W. McMullen was appointed to our Board of Directors as Bayou City’s director nominee in August 2016. Mr. McMullen is the founder and managing partner of Bayou City an oil and gas focused private equity firm based in Houston, Texas. Mr. McMullen founded Bayou City in 2015 after successfully managing a smaller private equity vehicle, Bayou City Energy Partners (“BCEP”), focused on investments in the oil and gas sector. Prior to BCEP, Mr. McMullen served as Vice President at White Deer Energy from August 2012 to October 2014, an oil and gas focused private equity firm, where he was responsible for origination, analysis, structuring and execution of upstream investments. Before White Deer Energy, Mr. McMullen served as an Associate at Denham Capital from August 2010 to July 2012. Prior to Denham Capital, Mr. McMullen served as an Analyst in UBS Investment Bank’s Global Energy group. Mr. McMullen earned his Bachelor’s degree in Economics, with Honors, from Harvard University.

Mickey Ellis has served as a director since our inception in 1987. Mrs. Ellis is actively involved in the leadership of charitable organizations, as a Board Member of The Confessing Movement of the United Methodist Church, Committee Member on several committees within Grace Fellowship United Methodist Church, and Building Relocation Coordinator for Mission Bend Christian Academy. She is a major fundraiser for the Susan G. Komen Foundation, student at the Bible Seminar Master of Divinity, and an active volunteer for CanCare. Ms. Ellis is the spouse of Michael E. Ellis, our Chairman, Chief Operating Officer and Vice President of Engineering. 

Mark Stoner was appointed to our Board of Directors as Bayou City’s second director nominee in September 2016. Mr. Stoner is a partner at BCE. Prior to joining BCE in 2015, Mr. Stoner was the Vice President of Finance of Alta Mesa. Mr. Stoner joined us in March 2008 and helped oversee our financing. While he was our Vice President of Finance, Mr. Stoner had leadership roles in the initial and subsequent high yield debt offerings as well as its recapitalization by HPS in 2014 and was a member of the acquisition and divestiture team which sourced and evaluated acquisition and divestiture opportunities. Prior to joining us, Mr. Stoner worked as a Financial Analyst at Leor Energy from 2006 to 2007. Mr. Stoner earned his Bachelor’s degree in Business from Southwestern University.

Qualifications of Directors

Mr. Chappelle’s experience as our Chief Executive Officer since 2004, combined with his significant equity ownership of us, and over 30 years of experience in the oil and gas industry uniquely qualify him to serve as a director of our General Partner.

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Mr. Ellis is our founder; his experience in that capacity and as one of our executive officers since 1987 provide him intimate knowledge of our operations, finances and strategy and uniquely qualifies him to serve as the Chairman of our General Partner.

Ms. Ellis’ role in working with us since our inception in 1987 provides her with valuable knowledge of our business and operations and uniquely qualifies her to serve as a director of our General Partner. 

Mr. Dimitrievich provides the Board of Directors with significant financial and energy expertise which uniquely qualifies him to serve as a director of our General Partner.

Mr. McCabe’s experience as our Chief Financial Officer since 2006 and over 25 years of corporate finance experience uniquely qualifies him to serve as a director of our General Partner.

Mr. Cole’s experience as our Chief Technical Officer since 2015 and over 25 years of domestic and international oilfield experience in well completions, and well simulations design and execution uniquely qualifies him to serve as a director of our General Partner.

Mr. McMullen provides the Board of Directors with significant financial and energy expertise which uniquely qualifies him to serve as a director of our General Partner.

Mr. Stoner provides the Board of Directors with significant financial and energy expertise which uniquely qualifies him to serve as a director of our General Partner.

Audit and Compensation Committee

We do not have a formal compensation committee and our full Board of Directors serves as our audit committee. Because we do not have any securities on a national securities exchange or on an inter-dealer quotation system, we are not subject to a number of the corporate governance requirements of the SEC or of any national securities exchange or inter-dealer quotation system. For example, we are not required to have a board of directors comprised of a majority of independent directors or to have an audit committee comprised of independent directors. Accordingly, our Board of Directors has not made any determination as to whether any of the members of our Board of Directors or committees thereof would qualify as independent under the listing standards of any national securities exchange or any inter-dealer quotation system or under any other independence definition. Additionally, for the same reason, we have not yet determined whether any of our directors is an audit committee financial expert.

Code of Ethics

The Board of Directors has adopted a Code of Ethics for Senior Financial Officers. The Code of Ethics is posted on the investor relations section of our website at www.altamesa.net and is available free of charge upon written request to 15021 Katy Freeway, Suite 400, Houston, Texas 77094.

Item 11. Executive Compensation 

Compensation Discussion and Analysis

This Compensation Discussion and Analysis, describes our compensation objectives and the principles underlying our compensation policy relating to 2016 compensation for our named executive officers (“NEOs”).

Our Board of Directors is responsible for overseeing our executive remuneration programs and the fair and competitive compensation of our executive officers and meets each year to review our compensation program and to determine compensation levels for the ensuing fiscal year.

Objectives of Our Compensation Program

Our executive compensation program is intended to motivate our executive officers to achieve strong financial and operating results for us. In addition, our program is designed to achieve the following objectives:

What Our Compensation Program is Designed to Reward

Our primary business objective is to increase value.  Our compensation program is designed to reward performance that contributes to the achievement of our business strategy. In addition, we reward qualities that we believe help achieve our strategy, such as teamwork; individual performance in light of general economic and industry specific conditions; performance that supports

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our core values; resourcefulness; the ability to manage our existing corporate assets; the ability to explore new avenues to increase oil and natural gas production and reserves; level of job responsibility; and tenure with us.

Elements of Our Compensation Program and Why We Pay Each Element

To accomplish our objectives, our compensation program is comprised of the following elements: base salary, cash bonus, long term incentives and benefits. Our Board of Directors approved and adopted a deferred compensation and supplemental executive retirement plan in 2013 and a performance appreciation rights plan in 2014.

We pay base salary in order to recognize each executive officer’s unique value and historical contributions to our success in light of salary norms in the industry and the general marketplace; to match competitors for executive talent; to provide executives with sufficient, regularly-paid income; and to reflect an executive’s position and level of responsibility.

We include an annual cash bonus as part of our compensation program because we believe this element of compensation helps to motivate executives to achieve key corporate objectives by providing annual recognition of achievement. The annual cash bonus also allows us to be competitive from a total remuneration standpoint.

We provide a supplemental executive retirement plan to certain key employees, including all our executive officers, to provide additional flexibility and tax planning advantages to them. In addition, the retirement benefits enhance employee compensation on a discretionary basis and encourage their continued service to us.

We grant performance appreciation rights units (“PARS”) as long-term compensation to certain key employees, including our executive officers, who make significant contributions to us.  The PARs are payable on a fixed determination date which is generally between five and ten years from the grant date of the award or in the event of a Liquidity Event (as defined in the PARs Plan), and therefore, provide the grantee with a significant interest in us tied to long-term performance.

We offer benefits such as a 401(k) plan and payment of insurance premiums in order to provide a competitive remuneration package as well as a measure of financial security to our employees.  In 2013 we introduced a deferred compensation plan offered to all employees, to provide flexibility and tax planning advantages to them.

How We Determine Each Element of Compensation

In determining the elements of compensation, we consider our ability to attract and retain executives as well as various measures of company and industrial performance including debt levels, revenues, cash flow, capital expenditures, reserves of oil and natural gas and costs. We did not retain a consultant with respect to determining 2016 compensation.

Messrs. Ellis, Chappelle, McCabe, and Murrell are parties to employment agreements with Alta Mesa Services. The employment agreements automatically renew annually, subject to prior notice of cancellation by either us or the executive. These employment agreements establish set minimum base salaries for each officer.  On March 25, 2014, these employment agreements were amended and restated and the salaries for each officer were set at $485,000, $485,000, $435,000, and $360,000 per annum, to Messrs. Ellis, Chappelle, McCabe and Murrell, respectively, which we believe are competitive with other independent oil and natural gas companies with whom we compete for managerial talent. In addition, the employment agreements provide that the executives are each entitled to an annual bonus equal to a percentage of his respective annual base salary if performance criteria set by the Board of Directors for the applicable period are met. The agreements also provide for benefits such as reimbursement of business expenses and participation in employee benefit plans.

Base salary. In reviewing base salaries, the Board of Directors takes into account a combination of subjective factors, primarily relying on their own personal judgment and experience. Subjective factors the Board of Directors considers include individual achievements, our performance, level of responsibility, experience, leadership abilities, increases or changes in duties and responsibilities and contributions to our performance. Mr. Ellis and Mr. Chappelle participate in and are present during the Board of Directors’ review and determination of their respective base salaries. For 2016, the Board of Directors set the base salaries for Messrs. Ellis, Chappelle and McCabe at $485,000, $485,000 and $435,000, respectively. In addition, the Board of Directors determined Mr. Murrell’s and Mr. Cole’s salary of $360,000 and $350,000 for 2016 was appropriate.

Bonus.  A portion of each executive’s total compensation may be paid as bonus compensation. The Board of Directors takes into consideration our achievements during the year and each executive’s contribution toward such achievements. While performance criteria may be set, the Board of Directors takes into account subjective factors in determining if these criteria were met. Bonuses for any one year are usually determined and paid in the second or third quarter of the following year. Accordingly, bonus compensation for our executive officers for 2016 has not yet been determined.    However, bonuses paid in 2016 for 2015 performance ranged from approximately 45% to 85% of base salary.

On September 23, 2014, the Board of Directors approved and adopted a long-term compensation plan, the Alta Mesa Holdings, LP Performance Appreciation Rights Plan (the “PARs Plan”), as amended and restated effective September 24, 2014, to provide long

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term incentive compensation to key employees and consultants who make significant contributions to us to align our employees with our long term performance. The PARs Plan is administered by the Board of Directors, which will determine from time to time which participants will participate in the PARs Plan, the number of PARs to be granted to each participant, the stipulated initial designated value (“SIDV”) of each PAR, the designated value of each PAR as of its valuation date, the vesting schedule of each PAR, and any other terms and conditions of the PAR award. Under the PARs Plan, there are special provisions for valuation and payment of a vested PAR award in the event of a Liquidity Event, which is generally defined as follows: an event that (a) satisfies the definition of “change in control” under Section 409A of the Code (“Section 409A”) and (b) is (i) a sale of the all of the assets of High Mesa, (ii) a disposition of all of the equity securities of High Mesa, (iii) an initial public offering of the equity securities of High Mesa or any of its subsidiaries that hold all or substantially all of the assets or (iv) a public offering resulting in gross proceeds of at least $300,000,000, provided that such event also qualifies as a change in control event under Section 409A.

A total of 1,000,000 PARs are available for grants to participants under the PARs Plan. The aggregate designated value of all 1,000,000 PARs is approximately equal to 10% of the fair market value of the aggregate interests of all the Class A members in our General Partner.

Absent an intervening Liquidity Event, payment of a PAR award is made on the fixed determination date elected in advance by the recipient of the PAR award, with such fixed determination date occurring no earlier than April 1 of the fifth year following the year of the grant and no later than ten years from the grant date. All payments made under the PARs Plan in any year are subject to a floating annual cap on the amount of all PAR awards paid under the PARs Plan in a given year (the “Annual Cap”). The Annual Cap is equal to 2.5% multiplied by the fair market value of the aggregate interests of all the Class A members in our General Partner minus $400,000,000.  If the Annual Cap applies in a year, the amount payable to a PAR award holder on the fixed determination date is his pro-rata amount of the aggregate payments to be made on that date as adjusted for the amount of Annual Cap remaining for that year. Any amounts in excess of the Annual Cap are paid in the next following year, again subject to the Annual Cap.

Upon the occurrence of a payment event, the participant will be entitled to receive a cash amount equal to the increase, if any, between the SIDV of the PAR as of its grant date and the designated value of the PAR as of its payment valuation date. No PARs will be settled in shares; rather, all PAR exercises will be settled solely in cash. Participants will have no rights whatsoever as a shareholder of our General Partner or of a subsidiary in respect of any PARs.

In 2016, the Board awarded 15,000 PARs to David Murrell, which vests over a five-year period.  The SIDV is $40 per unit and payout is based on the increase of the value of the units over the SIDV at the earlier of a Liquidity Event or at a fixed determination date which is generally at least five years from the grant date of the award.  In 2015, no PARs were awarded to any of the NEOs.  In 2014, the Board of Directors awarded 60,000 PARs to Michael A. McCabe, of which 50,000 units vested immediately, and the remaining 10,000 units vest over a three-year period.  The SIDV is $10.00 per unit, and payout is based on the increase of the value of the units over the SIDV as determined at the earlier of a Liquidity Event at or at a fixed determination date which is generally at least five years from the grant date of the award.  The Board of Directors also granted 15,000 PARs to David Murrell. The SIDV of 10,000 of the units is $40 per unit and vest over a five-year period, and the remaining 5,000 units have a SIDV of $30 per unit of which 1,500 vest immediately and the remaining 3,500 vest over a three-year period, and payout is based on the increase of the value of the units over the SIDV at the earlier of a Liquidity Event or at a fixed determination date which is generally at least five years from the grant date of the award. 

Benefits.  We provide company benefits or perquisites that we believe are standard in the industry to all of our employees. These benefits consist of a group medical and dental insurance program for employees and their qualified dependents and a 401(k) employee savings and protection plan. The costs of these benefits are paid for entirely by us. We do not provide employee life insurance amounts surpassing the Internal Revenue Service maximum. We make matching contributions to the 401(k) contribution of each qualified participant. We pay all administrative costs to maintain the plan. In addition, we provide Messrs. Ellis, Chappelle, McCabe, Murrell, and Cole with company automobiles. Beginning annually in 2014, we also reimburse each officer, with the exception of Mr. Cole, up to $5,000 annually for tax preparation and planning.

Nonqualified Deferred Compensation. We established a nonqualified deferred compensation plan in 2013, the Alta Mesa Holdings, L.P. Supplemental Executive Retirement Plan (the “Retirement Plan”), to provide additional flexibility and tax planning advantages to our senior executives and other key highly compensated employees.  The terms of such contributions may include a specified vesting schedule, intended to encourage continuous service to us.  If no schedule is specified with the award, the Retirement Plan provides for vesting based on years of service, with full vesting at three years.  Participants will receive a distribution of vested funds from the Retirement Plan in accordance with the distribution schedule established when the contributions are elected or awarded, with the option of deferring for a fixed time period or until separation from service.  On December 29, 2016,  the Board of Directors, in its discretion, authorized elective employer contributions to be credited to the accounts of Messrs. Chappelle, Ellis, McCabe, Murrell and Cole in the amounts of $1.6 million, $0.7 million, $0.6 million, $0.3 million and $0.5 million, respectively, effective January 1, 2017.  The Board of Directors elected to make this distribution subject to a five-year vesting schedule, with 20% vested each subsequent year, with the exception of Messrs. Murrell and Cole, with none vested in year one and 25% vested each subsequent year beginning in year two of the five-year vesting schedule.

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Other Compensation. As part of his employment agreement, we provide Mr. McCabe an apartment near our headquarters and pay his commuting expenses to and from his permanent home to Houston. In 2016, these housing and commuting expenses totaled approximately $89,000. We agreed to provide these benefits to Mr. McCabe because our Board believed it was necessary to retain Mr. McCabe’s services despite the fact that his permanent residence is outside of the Houston area. The Board of Directors considered the value of this additional compensation in evaluating Mr. McCabe’s total compensation package.

How Elements of Our Compensation Program are Related to Each Other

We view the various components of compensation as related but distinct and emphasize “pay for performance” with a portion of total compensation reflecting a risk aspect tied to our financial and strategic goals. We determine the appropriate level for each compensation component based in part, but not exclusively, on our view of internal equity and consistency, and other considerations we deem relevant, such as rewarding extraordinary performance.

Assessment of Risk

Our Board of Directors takes risk into account when making compensation decisions and has concluded that the executive compensation program as it is currently structured does not encourage excessive risk or unnecessary risk-taking.

Accounting and Tax Considerations

We have structured our compensation program to comply with Section 409A. If an employee is entitled to nonqualified deferred compensation benefits that are subject to Section 409A, and such compensation does not comply with Section 409A, then the benefits are generally taxable to the extent they are not subject to a substantial risk of forfeiture. In such case, the employee is subject to regular federal income tax, interest and an additional federal income tax of 20% of the benefits includible in income.

Under the PARs Plan, participants are granted PARs with a SIDV.  The PARs vest over time (as specified in each grant, typically five years) and entitle the owner to receive a cash amount equal to the increase, if any, between SIDV and the designated value of the PAR on the payment valuation date.  The payment valuation date is the earlier of a Liquidity Event (as defined in the PARs Plan, but generally can be construed in accordance with the meaning of the term “change in control event”) or as a fixed determination date selected by the participant, which is no earlier than within the fifth year from the end of the year containing the grant date.  In the case of a Liquidity Event, the designated value of all PARs is to be based on the net sale proceeds (as defined in the PARs Plan) resulting from the Liquidity Event.  After any payment valuation date, rested PARs expire regardless of whether or not there is a payment relating thereto.  We are unable to express an opinion with respect to the likelihood of a Liquidity Event which would result in any payment under the PARs Plan or to estimate any amount which may become payable under the PARs Plan.  We consider the possibility of payment at a fixed determination date absent the occurrence of a Liquidity Event to be remote.  Therefore, we have not provided any amount for this contingent liability in our consolidated financial statements at December 31, 2016 or 2015.

Compensation Committee Report

As we do not have a formal compensation committee, our entire Board of Directors serves as our compensation committee. Our Board of Directors has reviewed and discussed the above Compensation Discussion and Analysis with management and, based on such review the related discussions and such other matters deemed relevant and appropriate to the Board of Directors, and the Board of Directors recommended that the Compensation Discussion and Analysis be included in this annual report on Form 10-K.

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Summary Compensation

The following table summarizes, with respect to our NEOs, information relating to the compensation earned for services rendered in all capacities during the fiscal years ended December 31, 2016, 2015 and 2014. None of the NEOs participate in a defined benefit pension plan.

 









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Narrative Disclosure to Summary Compensation Table

Employment agreements

Mr. Chappelle

Mr. Chappelle entered into an amended and restated employment agreement on March 25, 2014 that provides that he will act as President and Chief Executive Officer until March 25, 2018, subject to automatic one year renewals of the term if neither party submits a notice of termination at least 60 days prior to the end of the then-current term. This agreement may be terminated by either party, at any time, subject to severance obligations in the event Mr. Chappelle is terminated by us without cause or he dies or is disabled.

Mr. Chappelle’s employment agreement provides for a minimum base salary of $485,000 and an annual bonus equal to a percentage of his base salary paid during each such annual period, such percentage to be established by our Board of Directors in the Board’s sole discretion.

Mr. Ellis

Mr. Ellis entered into an amended and restated employment agreement on March 25, 2014 that provides that he will act as Vice President and Chief Operating Officer until March 25, 2018, subject to automatic one year renewals of the term if neither party submits a notice of termination at least 60 days prior to the end of the then-current term. This agreement may be terminated by either party, at any time, subject to severance obligations in the event Mr. Ellis is terminated by us without cause or he dies or is disabled.

Mr. Ellis’ employment agreement provides for a minimum base salary of $485,000 and an annual bonus equal to a percentage of his base salary paid during each such annual period, such percentage to be established by our Board of Directors in the Board’s sole discretion.

Mr. McCabe

Mr. McCabe entered into an amended and restated employment agreement on March 25, 2014 that provides that he will act as Vice President and Chief Financial Officer until March 25, 2018, subject to automatic one year renewals of the term if neither party submits a notice of termination at least 60 days prior to the end of the then-current term. This agreement may be terminated by either party, at any time, subject to severance obligations in the event Mr. McCabe is terminated by us without cause or he dies or is disabled.

Mr. McCabe’s employment agreement provides for a minimum base salary of $435,000 and an annual bonus equal to a percentage of his base salary paid during each such annual period, such percentage to be established by our Board of Directors in the Board’s sole discretion.

Mr. McCabe’s employment agreement also provides that he is allowed to work from his residence in Massachusetts as well as in our Houston office so long as he is capable of performing his duties assigned to him. In his employment agreement, we also agree to provide Mr. McCabe with suitable housing (or a housing allowance) and an automobile or reimbursement for the lease of an automobile while he is in Houston.

Mr. Murrell

Mr. Murrell entered into an amended and restated employment agreement on March 25, 2014 that provides that he will act as Vice President of Land and Business Development until March 25, 2015, subject to automatic one year renewals of the term if neither party submits a notice of termination at least 60 days prior to the end of the then-current term. This agreement may be terminated by either party, at any time, subject to severance obligations in the event Mr. Murrell is terminated by us without cause or he dies or is disabled.

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Mr. Murrell’s employment agreement provides for a minimum base salary of $360,000 and an annual bonus equal to a percentage of his base salary paid during each such annual period, such percentage to be established by our Board of Directors in the Board’s sole discretion, subject to a minimum of $50,000.

Grants of Plan-Based Awards for Fiscal Year 2016

There were no grants of plan-based awards to our NEOs during the fiscal year ended December 31, 2016.

Outstanding Equity Awards Value at 2016 Fiscal Year-End

There were no outstanding equity awards for our NEOs as of December 31, 2016.

Option Exercises and Equity Awards Vested in Fiscal Year 2016

There were no exercises of equity awards and no vesting of equity awards for our NEOs during fiscal 2016.

Pension Benefits

We do not provide pension benefits for our NEOs.

Nonqualified Deferred Compensation

We established the Retirement Plan, to provide additional flexibility and tax planning advantages to our senior executives and other key highly compensated employees.  The Board of Directors administers the Retirement Plan, and at its sole discretion, designates employees who are eligible to participate.  Participants may defer up to 90% of their salary and up to 100% of their cash bonus under the Retirement plan.   The Board of Directors may also, at its sole discretion, make elective employer contributions on behalf of selected participants.  The terms of such contributions may include a specified vesting schedule, intended to encourage continuous service to us.  If no schedule is specified with the award, the Retirement Plan provides for vesting based on years of service, with full vesting at three years.  Participants may withdraw vested funds from the Retirement Plan in accordance with the distribution schedule established when the contributions are elected or awarded, with the option of deferring for a fixed time period or until separation from service with us.  The Retirement Plan is an unsecured and unfunded promise to pay deferred cash compensation to its participants, who are our general creditors. 

The following table shows each NEOs accumulated benefits under our nonqualified deferred compensation plans for 2016.



 

(a) The amounts shown in this column are also included in “All Other Compensation” column on the Summary Compensation Table.

(b) Certain portions shown for each NEO were also reported in the Summary Compensation Table in prior years

(c) The contributions are subject to a five-year vesting schedule, with 20% vested each subsequent year.

(d) The contributions are subject to a five-year vesting schedule, with zero vested in year one and 25% vested each subsequent year beginning in year two of the five-year vesting period.

In 2016, no amounts of salary or bonus were elected to be deferred under the Retirement Plan by any NEO.  In 2014, one elective employer contribution was made for the account of Michael A. McCabe.  The Board of Directors elected to make this distribution subject to a three-year vesting schedule, with 50% vested immediately and 16.67% to vest each subsequent year.  In 2013, one elective employer contribution was made for the account of David Murrell.  The Board of Directors elected to make this distribution subject to a four-year vesting schedule, with 20% vested immediately and 20% to vest each subsequent year.    



Termination of Employment and Change–in–Control Provisions

Messrs. Chappelle, Ellis, McCabe and Murrell are parties to employment agreements that provide them with post–termination benefits in a variety of circumstances. The amount of compensation payable in some cases may vary depending on the nature of the

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termination, whether as a result of retirement/voluntary termination, involuntary not–for–cause termination, termination following a change of control and in the event of disability or death of the executive. The discussion below describes the varying amounts payable in each of these situations. It assumes, in each case, that the officer’s termination was effective as of December 31, 2016. In presenting this disclosure, we describe amounts earned through December 31, 2016 and, in those cases where the actual amounts to be paid out can only be determined at the time of such executive’s separation from us, our estimates of the amounts which would be paid out to the executives upon their termination.

Provisions under the Employment Agreements

Under the employment agreements, if the executive’s employment with us terminates, the executive is entitled to unpaid salary for the full month in which the termination date occurred. However, if the executive is terminated for cause, the executive is only entitled to receive accrued but unpaid salary through the termination date. In addition, if the executive’s employment terminates, the executive is entitled to unpaid vacation days for that year which have accrued through the termination date, reimbursement of reasonable business expenses that were incurred but unpaid as of the termination date, a pro rata portion of the annual bonus for that year and COBRA coverage as required by law. Salary and accrued vacation days are payable in cash lump sum less applicable withholdings. Business expenses are reimbursable in accordance with normal procedures.

If the executive’s employment is involuntarily terminated by us (except for cause or due to the death of the executive) or if the executive’s employment is terminated due to disability or retirement or by the executive for good reason, we are obligated to pay as additional compensation an amount in cash equal to two years, of the executive’s base salary in effect as of the termination date. Under the terms of Mr. Murrell’s amended and restated employment agreement, as of December 31, 2016, upon such involuntary termination, provides for 18 months’ base salary and two times the annual bonus then in effect.  Assuming termination as of December 31, 2016, for both Messrs. Chappelle and Ellis, the termination benefit would have been $970,000; for Mr. McCabe, $870,000; and for Mr. Murrell, $540,000. In addition, all vested amounts in the executive’s account balance under the Retirement Plan would be distributed.  Assuming termination as of December 31, 2016, Mr. Chappelle, Mr. Ellis, Mr. McCabe and Mr. Murrell would have received a distribution of $275,000, $175,000, $2,650,000 and $260,000.  Our executives are each entitled under their employment agreements to continued group health plan coverage following the termination date for the executive and the executive’s eligible spouse and dependents for the maximum period for which such qualified beneficiaries are eligible to receive COBRA coverage.  For the first twelve months of COBRA coverage, the executive shall not be required to pay more for COBRA coverage than officers who are then in active service for us and receiving coverage under the plan. Assuming termination as of December 31, 2016, for each of Messrs. Chappelle, Ellis, McCabe, and Murrell, this amount would have been $12.00 to each. Our total cost of providing this benefit would have been $20,830 for Mr. Chappelle, $30,422 for Mr. Ellis, $20,830 for Mr. McCabe, and $20,830 for Mr. Murrell.

“Cause” means:

“Good reason” means the occurrence of any of the following, if not cured and corrected by us or our successor, within 60 days after written notice thereof is provided by the executive to us or our successor:

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“Retirement” means the termination of the executive’s employment for normal retirement at or after attaining age 70, provided that the executive has been with us for at least five years.

The employment agreements do not separately provide for benefits upon a change of control.

The Retirement Plan generally defines “cause” as above for the employment agreements.  Under the terms of the Retirement Plan, separation from service for any reason other than cause would result in a distribution event for the participant’s vested account balance.  The terms of the Retirement Plan also include provisions whereby each participant’s account balance becomes immediately fully vested if the participant (i) is terminated during the first year after a change in control event for any reason other than cause or (ii) terminates due to death or disability.  Normal retirement age is defined under the Plan as 65 years of age.

Compensation of Directors

The employee and non-employee members of the Board of Directors do not receive compensation for their services as directors. However, our directors may be reimbursed for their expenses in attending Board of Directors meetings.

Compensation Committee Interlocks and Insider Participation

We do not currently have a compensation committee or an equivalent committee. None of our NEOs has served as a director or member of the compensation committee of any other entity whose executive officers served as a director or member of our compensation committee.

Compensation Committee Report

As we do not have a formal compensation committee, our entire Board of Directors serves as our compensation committee. Our Board of Directors has reviewed and discussed the above Compensation Discussion and Analysis with management and, based on such review the related discussions and such other matters deemed relevant and appropriate to the Board of Directors, and the Board of Directors recommended that the Compensation Discussion and Analysis be included in this Annual Report on Form 10-K.



Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

The following table sets forth as of March 30, 2017 the limited partnership interests in Alta Mesa beneficially owned by:

As of March 30, 2017, we had 50,045 Class A units and 100,000 Class B Units issued and outstanding.



 

 

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Securities Authorized for Issuance under Equity Compensation Plans

We do not have any equity compensation plans.

Item 13. Certain Relationships and Related Transactions, and Director Independence

We do not have any formal policy with respect to the review and approval of related party transactions.    A “Related Party Transaction” is any transaction, arrangement or relationship where we are a participant, the Related Party (defined below) had, has or will have a direct or indirect material interest, and the aggregate amount involved is expected to exceed $120,000 in any calendar year. “Related Party” includes (a) any person who is or was (at any time during the last fiscal year) an executive officer, director or nominee for election as a director; (b) any person or group who is a beneficial owner of more than 5% of our voting securities; (c) any immediate family member of a person described in provisions (a) or (b) of this sentence; or (d) any entity in which any of the foregoing persons is employed, is a partner or has a greater than 5% beneficial ownership interest.

Ownership in Us and Our General Partner 

Michael E. Ellis, our Chairman and Chief Operating Officer, and his spouse Mickey Ellis, one of our directors, indirectly own 85.06% of our Class A interests. Our General Partner is owned by (1) Alta Mesa Resources, LP, an entity owned by Michael E. Ellis and Mickey Ellis, and (2) High Mesa. Our General Partner has a 0.18% interest in us.

During 2016 and 2015 Michael E. Ellis, our founder, Chief Operating Officer, and Chairman of the Board, received no capital distributions from us.

During 2016 and 2015 our Class B limited partner, High Mesa Inc. contributed $300 million and $20 million to us, respectively.  On December 31, 2016, High Mesa purchased from BCE and contributed interests in 24 producing wells drilled under the joint development agreement to us.  High Mesa’s equity contribution was recorded at the fair value of the wells contributed of approximately $65.7 million and included contributed cash of $11.3 million, of which $7.9 million was collected subsequent to year end.

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Founder Notes

We were founded in 1987 by Mr. Ellis and we or our subsidiaries have over time entered into promissory notes to repay Mr. Ellis for contributions of working capital and other amounts. The founder notes bear interest at 10.0% paid-in-kind, mature on December 31, 2021 and are unsecured and subordinated to all of our debt. Interest and principal are payable at maturity.

The founder notes are subordinate to the paid in kind notes of our Class B limited partner. The founder notes are also subordinated to the rights of the holders of Class B units to receive distributions under our partnership agreement and subordinated to the rights of the holders of Series B preferred stock of our Class B limited partner to receive payments. Our founder shall convert the founder notes into shares of common stock of High Mesa upon certain conditions in the event of an initial public offering of High Mesa. The aggregate amount payable under the founder notes was $27.0 million and $25.7 million at December 31, 2016 and December 31, 2015, respectively. During the years ended December 31, 2016, 2015 and 2014, no amounts were paid in principal or interest. Interest on the founder notes payable is not compounded and amounted to $1.2 million in each of the years ended December 31, 2016, 2015 and 2014. Such amounts have been added to the balance of the founder notes.

Land Consulting Services

David Murrell, our Vice President of Land and Business Development, is the principal of David Murrell & Associates, which provides land consulting services to us. The primary employee of David Murrell & Associates is his spouse, Brigid Murrell. Services are provided at a pre-negotiated hourly rate based on actual time employed by us. Total expenditures under this arrangement for the years ended December 31, 2016, 2015 and 2014, were approximately $146,000, $133,000 and $150,000. The contract may be terminated by either party without penalty upon 30 days’ notice.

Employee and Distribution

David McClure, our Vice President of Facilities and Midstream, and the son-in-law of our CEO, Harlan H. Chappelle, received total compensation of $425,000, $275,000, and $450,000 for the years ended December 31, 2016, 2015 and 2014. Additionally, his position provides him with the use of a company vehicle, similar to our other Vice Presidents whose duties include field oversight.

David Pepper, one of our landmen, and the cousin of our Vice President of Land and Business Development David Murrell, received total compensation of $180,000, $146,000, and $260,000 for the years ended December 31, 2016, 2015 and 2014. Additionally, his position provides him with the use of a company vehicle, similar to our other landman whose duties include field oversight.

Midstream Asset Sale and Land Purchase

On December 31, 2014, we sold our interests in a partially constructed pipeline and gas processing plant at cost to Northwest Gas Processing, LLC (“NWGP”) for $25.5 million cash and short-term note receivable of $8.5 million, while recording no gain or loss on the sale at December 31, 2014. The $8.5 million note receivable, dated December 31, 2014, bears interest at 8% per annum, interest payable only in quarterly installments beginning January 1, 2015, and matures on December 31, 2019. Immediately after the consummation of the transaction, NWGP’s obligation under the $8.5 million promissory note was transferred to High Mesa Services, LLC, a subsidiary of High Mesa.  On December 31, 2015, we repurchased a small portion of land originally sold to NWGP at cost of $0.7 million.

NWGP Services Agreement

We are party to a services agreement dated January 1, 2016 with NWGP.  Pursuant to the agreement, we agree to provide administrative and management services to NWGP relating to the midstream assets we sold to NWGP on December 31, 2014.  During the year ended December 31, 2016 NWGP was billed for management services provided in the amount of approximately $0.1 million.  High Mesa owns a controlling interest in NWGP.



Joint Development Agreement

 Our wholly-owned subsidiary Oklahoma Energy entered into a joint development agreement, dated January 13, 2016, with BCE, a fund advised by Bayou City, to fund a portion of our drilling operations in Kingfisher County, Oklahoma. Our General Partner’s directors Mark Stoner and William W. McMullen are partners at Bayou City. The drilling program will fund the development of 80 wells, which will be developed in four tranches of 20 wells each. On December 31, 2016, High Mesa purchased from BCE and contributed interests in 24 producing wells, the Contributed Wells, drilled under the joint development agreement to us. The pre-tax present value discounted at ten percent for the Contributed Wells as of the effective date of October 1, 2016 was approximately $80 million. In connection with the acquisition of the Contributed Wells, the joint development agreement was amended to exclude the Contributed Wells from the drilling program. The drilling program will fund the development of 80 additional wells in four tranches of 20 wells each.  BCE has committed to fund 100% of Oklahoma Energy’s working interest share of drilling and development costs for each well in which BCE elects to participate, provided that to the extent that the total cost of drilling the

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wells in any tranche exceeds $64 million, Oklahoma Energy will be responsible for its and BCE’s working interest share of the drilling costs in such tranche exceeding such limit.

In exchange for the payment of drilling and completion costs, BCE will receive 80% of Oklahoma Energy’s working interest in each Joint Well, which interest will be reduced to 20% of Oklahoma Energy’s initial working interest upon BCE achieving a 15% internal rate of return in a tranche and further reduced to 12.5% of Oklahoma Energy’s initial interest upon BCE achieving a 25% internal rate of return. Upon the achievement of these return thresholds, the interest BCE relinquishes will automatically revert back to Oklahoma Energy. Following the completion of each Joint Well, BCE and Oklahoma Energy will bear their proportionate working interest share of all subsequent costs and expenses related to such Joint Well. The approximate dollar value of the amount involved in this transaction and Messrs. Stoner and McMullen’s interests in the joint development agreement depends on a number of factors outside Messrs. Stoner and McMullen’s control and are not known at this time. As of December 31, 2016, we recorded $42.5 million in advances from related party on our consolidated balance sheets, which represents net advances from BCE for their working interest share of the drilling and development cost as part of our joint development agreement.



Gathering Agreements

 

On August 31, 2015, Oklahoma Energy entered into a Crude Oil Gathering Agreement (the “Crude Oil Gathering Agreement”) and Gas Gathering and Processing Agreement (the “Gas Gathering and Processing Agreement”) with KFM, which was subsequently amended on February 3, 2017, effective as of December 1, 2016.  High Mesa owns a minority interest in KFM. Alta Mesa also indirectly owns a minimal interest in KFM through its less than 10% ownership of AEM.  We have committed the oil and natural gas production from our Kingfisher County acreage, not otherwise committed to others, to KFM.

 

Under the Crude Oil Gathering Agreement and the Gas Gathering and Processing Agreement, Oklahoma Energy dedicates and delivers to KFM crude oil and natural gas and associated natural gas liquids produced from present and future wells located in certain lands in Kingfisher, Logan, Canadian, Blaine and Garfield Counties in Oklahoma to designated receipt points on KFM’s system for gathering and processing. The Crude Oil Gathering Agreement and Gas Gathering and Processing Agreements will remain in effect for a primary term of 15 years from the in-service date of July 1, 2016 and, after the primary term, an extended term for as long as there are wells connected to the system that continue to produce crude oil or gas in commercial (paying) quantities.

 

Under the Crude Oil Gathering Agreement, KFM operates a crude oil gathering system for the purpose of providing gathering services to Oklahoma Energy. KFM receives from Oklahoma Energy a fixed service fee per barrel of crude oil delivered. The fixed service fee consists of a fee for providing gathering services and is subject to an annual percentage increase tied to the consumer price index. Oklahoma Energy also pays KFM its allocated share, if any, of the electricity consumed in the operation of the crude oil gathering system.

 

Under the Gas Gathering and Processing Agreement, KFM operates a gas gathering and processing system for the purpose of providing gathering and processing services to Oklahoma Energy. KFM provides gathering and processing services for a fixed fee. The fixed service fee consists of (i) a gathering fee assessed on the volume of gas allocated to the central receipt point, (ii) a processing fee assessed on the volume of gas allocated to the central receipt point, (iii) a dehydration fee assessed on the volume of gas allocated to the central receipt point, (iv) a compression fee for each stage of compression for any volume of gas allocated to the central receipt point and (v) a facility fee for the first four years of the agreement, at which time the facility fee is removed.  Beginning in January 2021, each fee is subject to an annual percentage increase tied to the consumer price index.  Oklahoma Energy also pays KFM its allocated share, if any, of the electricity consumed in the operation of the gas gathering and processing system. Under the Gas Gathering and Processing Agreement, we have secured firm processing rights of 260 MMcf/d at the expanding KFM plant.

 

The aggregate amounts paid under the Crude Oil Gathering Agreement and Gas Gathering and Processing Agreement will depend on the volumes produced and gathered pursuant to these agreements. Under such agreements, the fees for the year ended December 31, 2016 were $7.5 million.  These fees are recorded as marketing and transportation expense in the consolidated statements of operations.  As of December 31, 2016, we accrued approximately $3.0 million as a reduction to the accounts receivable on the consolidated balance sheets for fees related to marketing and transportation for the KFM plant.



Subsequent to year-end, Oklahoma Energy entered into an agreement with KFM whereby we made a deposit of $10.0 million on January 13, 2017 to KFM to provide us with 100,000 Dth/d for firm transportation.  The deposit will be released back to us as we utilize the marketing and transportation services in 2018. 

Director Independence

Our Board of Directors consists of eight members, four of whom are non-employee directors. Because we only have debt securities registered with the SEC under the Exchange Act and because we do not have a class of securities listed on any national securities exchange, national securities association or inter-dealer quotation system, we are not required to have a board of directors comprised of a majority of independent directors under SEC rules or any listing standards. Accordingly, our Board of Directors has

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not made any determination as to whether the non-employee directors satisfy any independence requirements applicable to board members under the rules of the SEC or any national securities exchange, inter-dealer quotation system or any other independence definition.

Item 14. Principal Accountant Fees and Services

Our Board of Directors selected BDO USA, LLP (“BDO”), an independent registered public accounting firm, to audit our consolidated financial statements for each of the fiscal years ended December 31, 2016, 2015 and 2014. Aggregate fees for professional services rendered to us by BDO for the years ended December 31, 2016 and 2015 were as follows:





Audit Fees

The audit fees for the years ended December 31, 2016 and 2015, respectively, were for professional services rendered for the audits of our consolidated financial statements and review of our quarterly financial statements and services provided in connection with securities offerings. 

Audit-Related Fees

Audit-related fees for the years 2016 and 2015 include fees for the audit of our 401(k) employee savings plan.

Pre-Approval Policies and Procedures

        We currently have no board committees. Our Board of Directors has adopted policies regarding the pre-approval of auditor services. Specifically, the Board of Directors approves all services to be provided by the independent public accountants at its March meeting. All additional services must be pre-approved on a case-by-case basis. Our Board of Directors reviews the actual and budgeted fees for the independent public accountants periodically at regularly scheduled board meetings. All of the services provided by BDO during fiscal 2016 and 2015 were approved by the Board of Directors. 

PART IV

Item 15. Exhibits and Financial Statement Schedules

(a)Documents filed as part of this report:

1.Financial Statements:

(i)Independent Registered Public Accounting Firms’ Report

(ii)Consolidated Balance Sheets as of December 31, 2016 and 2015

(iii)Consolidated Statements of Operations for each of the years in the three-year period ended December 31, 2016

(iv)Consolidated Statements of Changes in Partners’ Capital (Deficit) for each of the years in the three-year period ended December 31, 2016

(v)Consolidated Statements of Cash Flows for each of the years in the three-year period ended December 31, 2016

(vi)Notes to Consolidated Financial Statements

(vii)Supplemental Oil and Natural Gas Information (Unaudited)

2.Financial Statement Schedules:

(i)All schedules are omitted as they are not applicable, not required or the required information is included in the consolidated financial statements or notes thereto.

3.Exhibits:

 



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Item 16. Form 10-K Summary

None.

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SIGNATURES

In accordance with Section 13 or 15(d) of the Exchange Act, the registrant caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

ALTA MESA HOLDINGS, L.P.

(Registrant)

 



Dated March 30, 2017

In accordance with the Exchange Act, this report  has been signed below on the 30th day of March, 2017, by the following persons on behalf of the registrant and in the capacities indicated.

 

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GLOSSARY OF CERTAIN OIL AND NATURAL GAS TERMS

The definitions set forth below apply to the indicated terms as used in this Annual Report on Form 10-K. All volumes of natural gas referred to are stated at the legal pressure base of the state or area where the reserves exist and at 60 degrees Fahrenheit and in most instances are rounded to the nearest major multiple.

“3-D seismic”. (Three-Dimensional Seismic Data) Geophysical data that depicts the subsurface strata in three dimensions. 3-D seismic data typically provides a more detailed and accurate interpretation of the subsurface strata than two-dimensional seismic data.

“Bbl”. One stock tank barrel, of 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.

“Bcfe”. One billion cubic feet of natural gas equivalent with one barrel of oil converted to six thousand cubic feet of natural gas. The ratio of six thousand cubic feet of natural gas to one Bbl of oil or natural gas liquids is commonly used in the oil and natural gas business and represents the approximate energy equivalency of six thousand cubic feet of natural gas to one Bbl of oil or natural gas liquids, and does not represent the sales price equivalency of natural gas to oil or natural gas liquids. Currently, the sales price of one Bbl of oil or natural gas liquids is significantly higher than the sales price of six thousand cubic feet of natural gas.

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

“BOE”.  One barrel of oil equivalent determined using the ratio of six Mcf of natural gas to one barrel of oil, condensate or natural gas liquids. The ratio of six Mcf of natural gas to one Bbl of oil or natural gas liquids is commonly used in the oil and natural gas business and represents the approximate energy equivalency of six Mcf of natural gas to one Bbl of oil or natural gas liquids, and does not represent the sales price equivalency of natural gas to oil or natural gas liquids. Currently, the sales price of one Bbl of oil or natural gas liquids is significantly higher than the sales price of six Mcf of natural gas.

“Btu or British Thermal Unit”. The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.

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

“DD&A”. Depreciation, depletion and amortization.

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

“Developed oil and natural gas reserves”. Developed oil and natural gas reserves are reserves of any category that can be expected to be recovered: (i) through existing wells with existing equipment and operating methods or in which the cost of the related equipment is relatively minor compared to the cost of a new well; and (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

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

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

“Dry hole costs”. Costs incurred in drilling a well, assuming a well is not successful, including plugging and abandonment costs.

“Enhanced recovery”. The recovery of oil and natural gas through the injection of liquids or gases into the reservoir, supplementing its natural energy. Enhanced recovery methods are often applied when production slows due to depletion of the natural pressure.

“Exploratory well”. A well drilled to find and produce natural gas or oil reserves not classified as proved, to find a new reservoir in a field previously found to be productive of natural gas or oil in another reservoir or to extend 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 or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations.

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

“Fracing, fracture stimulation technology, hydraulic fracturing”. The technique of improving a well’s production or injection rates by pumping a mixture of fluids into the formation and rupturing the rock, creating an artificial channel. As part of this technique, sand or other material may also be injected into the formation to keep the channel open, so that fluids or natural gases may more easily flow through the formation.

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“Gross acres or gross wells”. The total acres or wells, as the case may be, in which a working interest is owned.

“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.

“Infill wells”. Wells drilled into the same pool as known producing wells so that oil or natural gas does not have to travel as far through the formation.

“Lease operating expenses”. The expenses of lifting oil or natural gas from a producing formation to the surface, constituting part of the current operating expenses of a working interest, and also including labor, superintendence, supplies, repairs, short-lived assets, maintenance, allocated overhead costs, workover, ad valorem taxes, insurance and other expenses incidental to production, but excluding lease acquisition or drilling or completion expenses.

“MBbl”. One thousand barrels of crude oil, condensate or natural gas liquids.

“Mcf”. One thousand cubic feet of natural gas.

“Mcfe”. One thousand cubic feet equivalent determined using the ratio of six Mcf of natural gas to one barrel of oil, condensate or natural gas liquids. The ratio of six Mcf of natural gas to one Bbl of oil or natural gas liquids is commonly used in the oil and natural gas business and represents the approximate energy equivalency of six Mcf of natural gas to one Bbl of oil or natural gas liquids, and does not represent the sales price equivalency of natural gas to oil or natural gas liquids. Currently, the sales price of one Bbl of oil or natural gas liquids is significantly higher than the sales price of six Mcf of natural gas.

“Mcfe/d”. Mcfe per day.

“MMBtu”. One million British thermal units.

“MMcf”. One million cubic feet of natural gas.

“MMcfe”. Million cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

“MMcfe/d”. MMcfe per day.

“MMBbl”. One million barrels of crude oil, condensate or natural gas liquids.

“NGLs” or “natural gas liquids.” Hydrocarbons found in natural gas which may be extracted as liquefied petroleum gas and natural gasoline.

“NYMEX”. The New York Mercantile Exchange.

“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.

“Non-operated working interests”. The working interest or fraction thereof in a lease or unit, the owner of which is without operating rights by reason of an operating agreement.

“Pay”. A reservoir or portion of a reservoir that contains economically producible hydrocarbons. The overall interval in which pay sections occur is the gross pay; the smaller portions of the gross pay that meet local criteria for pay (such as a minimum porosity, permeability and hydrocarbon saturation) are net pay.

“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.

“Prospect”. A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.

“PDNP”. Proved developed non-producing reserves.

“PDP”. Proved developed producing reserves.

“Proved reserves”. Proved oil and natural gas 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, 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.

“Proved undeveloped reserves (“PUD”)”. Proved undeveloped oil and natural 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 recompletion. Undrilled acreage is considered proved where adjacent undrilled portions of the reservoir can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available

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geoscience and engineering data.  In addition, 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 and these locations must have a development plan that calls for development within five years, unless specific circumstances justify a longer time.  In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.  Finally, reserves which can be produced through the application of improved recovery techniques, including injection, may be included upon successful testing of a pilot project in a representative area or analogous reservoir or if other evidence using reliable technology establishes the reasonable certainty of the engineering analysis.  Such improved recovery techniques must be approved for development by all necessary parties and entities including governmental entities. 

“PV-10”. When used with respect to oil and natural gas reserves, PV-10 means the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development and abandonment costs, using prices and costs in effect at the determination date, before income taxes, and without giving effect to non-property related expenses, discounted to a present value using an annual discount rate of 10% in accordance with the guidelines of the SEC. PV-10 is not a financial measure calculated in accordance with generally accepted accounting principles (“GAAP”) and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. Neither PV-10 nor Standardized Measure represents an estimate of the fair market value of our oil and natural gas properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies without regard to the specific tax characteristics of such entities. Our PV-10 is the same as our standardized measure for the periods presented in this report.

“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.

“Reserve life index”. A measure of the productive life of an oil and natural gas property or a group of properties, expressed in years.

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

“Spacing”. The distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres, e.g., 40-acre spacing, and is often established by regulatory agencies.

“Standardized measure”. Standardized measure is the present value of estimated future net revenues to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the Securities and Exchange Commission, without giving effect to non — property related expenses such as certain general and administrative expenses, debt service or depreciation, depletion and amortization and discounted using an annual discount rate of 10%. Our standardized measure includes future obligations under the Texas gross margin tax, but it does not include future federal income tax expenses because we are a partnership and are not subject to federal income taxes. Our standardized measure is the same as our PV-10 for the periods presented in this report.

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

“Unit”. The joining of all or substantially all interests in a reservoir or field, rather than a single tract, to provide for development and operation without regard to separate property interests. Also, the area covered by a unitization agreement.

“Waterflood”. The injection of water into an oil reservoir to “push” additional oil out of the reservoir rock and into the wellbores of producing wells. Typically an enhanced recovery process.

“Wellbore”. The hole drilled by the bit that is equipped for natural gas production on a completed well. Also called well or borehole.

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