Item 1. Business
Overview
Alta Mesa Holdings, LP (“Alta Mesa,” the “Company,” “us,” “our,” or “we”) is an 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.
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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, 2017, we have assembled a highly contiguous position of approximately 130,000 net acres largely in the up-dip, naturally-fractured oil portion of the STACK in eastern Kingfisher County, Oklahoma. Our drilling locations primarily 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 seven horizontal drilling rigs in the STACK with plans to increase the number of rigs by the end of 2018. Following our business combination with Alta Mesa Resources, Inc. (formerly Silver Run Acquisition Corporation II, a Delaware corporation (“AMR”)) (as described below), our anticipated capital expenditures for 2018 of $568 million are all allocated 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, 2017, we increased our STACK production at a compound annual growth rate (“CAGR”) of approximately 80%. We increased our leasehold interests from approximately 45,000 net acres in early 2015 to approximately 130,000 net acres as of December 31, 2017 primarily through the acquisition of largely undeveloped leasehold.
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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.
As of December 31, 2017, our estimated total proved reserves were approximately 182.7 MMBOE, of which 96% were in the STACK. The estimated total proved reserves in the STACK were approximately 176.2 MMBOE, representing a 36% increase over 2016 year-end estimated proved reserves of 129.6 MMBOE in the STACK. Our total proved reserve mix is approximately 40% oil, 40% natural gas, and 20% natural gas liquids.
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Business Combination with Alta Mesa Resources, Inc.
On August 16, 2017, we entered into a Contribution Agreement (the “AM Contribution Agreement”) with AMR, High Mesa Holdings, LP, a Delaware limited partnership (the “AM Contributor”), High Mesa Holdings GP, LLC, a Texas limited liability company and the sole general partner of the AM Contributor, Alta Mesa Holdings GP, LLC, a Texas limited liability company and our sole general partner (“AMH GP”), and, solely for certain provisions therein, the equity owners of the AM Contributor. Simultaneous with the execution of the AM Contribution Agreement, AMR entered into (i) a Contribution Agreement (the “KFM Contribution Agreement”) with KFM Holdco, LLC, a Delaware limited liability company (the “KFM Contributor”), Kingfisher Midstream, LLC, a Delaware limited liability company (“Kingfisher”), and, solely for certain provisions therein, the equity owners of the KFM Contributor; and (ii) a Contribution Agreement (the “Riverstone Contribution Agreement” and, together with the AM Contribution Agreement and the KFM Contribution Agreement, the “Contribution Agreements”) with Riverstone VI Alta Mesa Holdings, L.P., a Delaware limited partnership (the “Riverstone Contributor”).
On February 9, 2018 (the “Closing Date”), we consummated the transactions contemplated by the Contribution Agreements and SRII Opco LP, a Delaware limited partnership (“SRII Opco LP”) acquired (a) (i) all of the limited partner interests in us and (ii) 100% of the economic interests and 90% of the voting interests in AMH GP (with (i) and (ii) collectively, the “AM Contribution”) and (b)
100% of the economic interests in Kingfisher (the “Kingfisher Contribution”). The acquisition of us and Kingfisher pursuant to the Contribution Agreements is referred to herein as the “business combination” and the transactions contemplated by the Contribution Agreements are referred to herein as the “Transactions.”
SRII Opco GP, LLC, a Delaware limited liability company (“SRII Opco GP”), the sole general partner of SRII Opco LP, is a wholly owned subsidiary of AMR. The limited partners of SRII Opco LP are the AM Contributor, the KFM Contributor and the Riverstone Contributor (collectively, the “Contributors”), AMR and certain funds managed by Highbridge. As a result of the Transactions, AMR has obtained control over the management of AMH GP and, consequently, us. AMR is a publicly traded corporation that is not under the control of any person. Prior to the closing of the Transactions, AMH GP, and consequently, us, was controlled by High Mesa and indirectly by our founder and Chief Operating Officer, Michael E. Ellis.
Harlan H. Chappelle, our Chief Executive Officer and a director, Michael Ellis, our Chief Operating Officer and a director and certain affiliates of Bayou City Energy Management, LLC, a Delaware limited liability company (“Bayou City”), and HPS Investment Partners, LLC, a Delaware limited liability company (“Highbridge”), continue to own an aggregate 10% voting interest in AMH GP following the closing. These existing owners were a party to a voting agreement with the AM Contributor and AMH GP, pursuant to which they agreed to vote their interests in AMH GP as directed by the AM Contributor. In connection with the closing of the Transactions, the parties amended and restated the voting agreement to include SRII Opco LP as a party and the existing owners agreed to vote their interests in AMH GP as directed by SRII Opco LP and appoint SRII Opco LP as their respective proxy and attorney-in-fact with respect to any voting matters related to their respective interests in AMH GP. The amended and restated voting agreement will continue in force until SRII Opco LP elects to terminate the agreement or, with respect to each existing owner individually, such existing owner no longer owns a voting interest in AMH GP. The closing of the business combination did not constitute a change of control under the indenture governing our 7.875% senior unsecured notes due December 15, 2024 (the “2024 Notes”).
Consideration
Pursuant to the AM Contribution Agreement, at the closing of the Transactions (the “Closing”), the AM Contributor received 138,402,398 common units representing limited partner interests (the “Common Units”) in SRII Opco LP. The AM Contributor also acquired from AMR a number of newly issued shares of non-economic capital stock of AMR, designated as Class C common stock, par value $0.0001 per share (the “Class C Common Stock”), corresponding to the number of Common Units received by the AM Contributor at the Closing.
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In addition to the above, for a period of seven years following the Closing, the AM Contributor will be entitled to receive an aggregate of up to $800 million in earn-out consideration to be paid in the form of Common Units (and acquire a corresponding number of shares of Class C Common Stock) as specified below if the 20-day volume-weighted average price (“20-Day VWAP”) of the Class A Common Stock of AMR equals or exceeds the following prices (each such payment, an “Earn-Out Payment”):
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The AM Contributor will not be entitled to receive a particular Earn-Out Payment on more than one occasion and, if, on a particular date, the 20-Day VWAP entitles the AM Contributor to more than one Earn-Out Payment (each of which has not been previously paid), the AM Contributor will be entitled to receive each such Earn-Out Payment. The AM Contributor will be entitled to the earn-out consideration described above in connection with certain liquidity events of AMR, including a merger or sale of all or substantially all of AMR’s assets, if the consideration paid to holders of Class A Common Stock in connection with such liquidity event is greater than any of the above-specified 20-Day VWAP hurdles.
AMR also contributed $554 million in cash to us at the Closing. AMR’s source for these funds was from the sale of its securities to investors in a public offering and in private placements. We used a portion of the amount to repay all outstanding balances under the senior secured revolving credit facility.
Exchange or Redemption of Common Units
Beginning 180 days after the Closing, the AM Contributor will have the right to exchange its Common Units for shares of AMR Class A Common Stock or cash (at AMR’s election). Upon any redemption of Common Units by the AM Contributor, a corresponding number of shares of Class C Common Stock owned by the AM Contributor will be cancelled.
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Amended Limited Partnership and Limited Liability Company Agreement
In connection with the closing of the business combination on February 9, 2018, AMH GP and SRII Opco LP entered into a Seventh Amended and Restated Agreement of Limited Partnership of Alta Mesa (the “Seventh Amended Partnership Agreement”). The Seventh Amended Partnership Agreement reflects, among other things, that SRII Opco LP is now the sole limited partner of Alta Mesa.
In addition, on February 9, 2018, the owners of AMH GP entered into a Sixth Amended and Restated Limited Liability Company Agreement of AMH GP (the “Sixth Amended LLC Agreement”), which was amended to, reflect that SRII Opco LP, now the holder of all of the Class A Units (as defined therein) is entitled to 100% of the economic rights with respect to AMH GP, and that SRII Opco LP is now the holder of 90% of the Class B Units (as defined therein) which are entitled to 100% of the voting rights with respect to AMH GP.
As described above, on February 9, 2018, all of the owners of AMH GP entered into an amended and restated voting agreement (the “Voting Agreement”) regarding the voting of their interests in AMH GP.
Appointment and Departure of Directors
In connection with the business combination, Michael A. McCabe, Homer “Gene” Cole, Mickey Ellis, Don Dimitrievich, William W. McMullen and Mark Stoner resigned from the board of AMH GP. In connection with the business combination, James T. Hackett was appointed to the board of AMH GP. Harlan H. Chappelle and Michael E. Ellis remain directors on the board of AMH GP. Our executive management team remains the same, except that Mr. Hackett is now Chairman of the Board.
Distribution of Non-Stack Assets
In connection with the closing of the business combination, we have completed our transition from a diversified asset base composed of a portfolio of conventional assets to an oil and liquids-rich resource play in the STACK. On February 8, 2018, we distributed the remainder of our non-STACK assets to AM Contributor as a dividend. At the time of the disposition, management estimated the carrying value of our remaining non-STACK assets to be $42.8 million with liabilities of $52.5 million, which liabilities include $44.6 million of asset retirement obligations. The remaining non-STACK assets distributed subsequent to year end will be reflected as discontinued operations in future filings when the criteria for discontinued operations for the remaining non-STACK are met under ASC 205-20, “Discontinued Operations”.
Amended and Restated Senior Secured Revolving Credit Facility
In connection with the closing of the business combination, we entered into the Eighth Amended and Restated Credit Agreement with Wells Fargo Bank, National Association, as the administrative agent (the “Eighth A&R credit facility”). The Eighth A&R credit facility is for an aggregate maximum credit amount of $1.0 billion with an initial $350.0 million borrowing base limit. The Eighth A&R credit facility 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 February 9, 2018, all outstanding balances under our credit facility were paid in full.
For further details of the business combinations please Note 19 - Subsequent Events in the consolidated financial statements.
Weeks Island Sale
During the fourth quarter of 2017, we sold our oil and natural gas properties in the Weeks Island field. Results of operations for Weeks Island field are reflected as discontinued operations in our consolidated financial statements for all periods presented. See Note 6 - Discontinued Operations to the consolidated financial statements for details. Operating revenues and expenses for all periods exclude discontinued operations in the Weeks Island field. As used herein, unless noted otherwise, amounts presented will not include the Weeks Island field.
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2017 Highlights
During 2017, we concentrated our efforts on developing our assets in the STACK play. Highlights from 2017 include:
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total estimated proved reserves increased by 43.9 MMBOE or 32% from 138.8 MMBOE (including Weeks Island) in 2016 to 182.7 MMBOE in 2017, primarily as a result of our focus on the successful drilling activity and development in the STACK;
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total production increased by 41% from 6.1 MMBOE in 2016 to 8.6 MMBOE in 2017;
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total average daily production from our assets in the STACK increased by 58% from approximately 13.0 MBOE/d in 2016 to 20.6 MBOE/d in 2017;
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total revenues from hydrocarbons increased 76% in 2017 as compared to 2016, as a result of higher commodity prices and higher production;
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drilled and completed 134 gross wells (59.1 net wells) in 2017 in the STACK and 37 gross wells of the 134 gross wells drilled and completed in the STACK were funded pursuant to the joint development agreement with BCE-STACK Development LLC (“BCE”) (described below);
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divested conventional assets in our previous core area Weeks Island field for approximately $22.5 million, as a result of a strategic shift in our operations to become a STACK pure-play company;
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invested approximately $314 million in our oil and natural gas properties in 2017, as compared to $214 million in 2016 (both totals exclude acquisitions);
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recognized impairment expense in 2017 of $30.3 million as compared to $16.3 million in 2016;
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 commodity prices in recent years. Commodity prices remained volatile, but generally increased on average in 2017 relative to 2016 in response to improving supply and demand fundamentals and other factors. Oil prices in particular showed significant signs of improvement in early 2018, with NYMEX West Texas Intermediate (“NYMEX WTI”) reaching $66.14 per barrel on January 26, 2018. As of March 20, 2018, NYMEX WTI was $63.40 per barrel and NYMEX Henry Hub was $2.68 per MMBtu. Commodity prices remain unpredictable and it is uncertain whether the increase in market prices experienced in recent months will be sustained. Therefore, we cannot predict with certainty the future prices for the commodities we produce and sell. 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.
Our anticipated capital expenditures, which include acquisitions, for 2018 are approximately $568 million. Additionally, we anticipate that up to an additional $25 million will be funded for 2018 drilling and completions activity in the STACK by BCE pursuant to our joint development agreement (described below). Following the business combination with AMR, our 2018 outlook is focused on the development of our assets in the STACK. Accordingly, we have allocated all of our 2018 capital expenditures to the STACK. We currently operate seven drilling rigs in the STACK and anticipate increasing to eight drilling rigs by the end of 2018, which will result in drilling a total of approximately 175 gross wells in the STACK.
Our Strategy
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Our primary business objective is to increase value through the execution of the following strategies:
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Economically grow production, cash flow and reserves by developing our extensive drilling inventory in the core of the STACK. We consider our large inventory of identified horizontal drilling locations in our primary target formations within the STACK to be relatively low-risk based on information gained from our own production history, the large number of existing wells in the area, the industry activity surrounding our acreage and the consistent and predictable geology on and surrounding our position. We intend to grow our reserves and production through the development of a multi-year inventory of identified drilling locations in our primary target formations within the STACK. These drilling locations represent a significant part of our growth strategy.
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Maximize the present value of future cash flows from our acreage position. We intend to increase the recovery of oil and natural gas from our acreage position in the most economically efficient manner possible to enhance future cash flows. To date, this effort has focused on developing our identified drilling locations, continuously optimizing well completions and horizontal and vertical spacing of our horizontal wells based on the results of our seven spacing tests. We also expect to establish the productive capability of additional formations including the Big Lime, Prue, Skinner, Red Fork, Cherokee Shale, Manning Lime, Woodford Shale and Hunton Lime formations. Based on results from our horizontal drilling program and those of offset operators, we believe significant development opportunities exist in these formations in the STACK as well as downspacing opportunities throughout our acreage position, thus potentially increasing our horizontal drilling inventory significantly.
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Expand drilling inventory through strategic acquisitions. We believe that our highly contiguous acreage position and extensive knowledge of the STACK will allow us to add acreage through grassroots leasing, acquisitions, pooling of interests and farm-ins. We believe our understanding of the geology, geophysics and reservoir properties of potential acquisition targets will allow us to identify and acquire highly prospective acreage in order to further grow our resource base. We increased our position in the STACK from approximately 45,000 net acres in early 2015 to approximately 130,000 net acres as of December 31, 2017 primarily through the acquisition of undeveloped acreage. We have
significant experience in successfully sourcing, evaluating and executing acquisition opportunities and intend to pursue future acquisitions, farm-ins and forced pooling to meet our strategic and financial objectives.
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Maximize single-well returns by optimizing drilling and completion techniques through the experience and expertise of our operating team. Our team uses a multi-disciplinary approach on an ongoing basis to evaluate our techniques for well targeting, drilling, completions and operating results and compares our methods and results against other operators in our area in order to improve our performance and identify opportunities to optimize our drilling and completion techniques. We have incorporated increased understanding of rock properties to target landing zones for horizontal wells, as well as optimized completion designs. A key element of cost reduction has been efficiency gains in drilling time, improving from an average of over 40 days from wells spud in 2012 to an average of 15 days in 2017.
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Strategically manage infrastructure and midstream services contracts to lower our costs. We seek to leverage existing legacy infrastructure, as well as exploit new infrastructure, to support our development of multi-well pad drilling. We also utilize various midstream and marketing solutions to increase realizations and to provide access to multiple downstream natural gas and NGL markets. We currently have preferred access to the Kingfisher system through a firm processing commitment without any minimum volume commitment obligations as our midstream commitments pertain to acreage dedications only. Several midstream companies have recently expanded their gathering systems and added processing capacity to serve the STACK. The Kingfisher system and plant are located primarily within our acreage footprint and began operation in the second quarter of 2016. With the planned Kingfisher expansion underway, the Kingfisher system provides us with dedicated offtake while improving NGL realizations as well as the opportunity to expand our volumes delivered to the system once the expansion has been completed.
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Preserve a strong and flexible capital structure to pursue our development program and acquisition opportunities. We seek to maintain a strong capital structure that protects our balance sheet and liquidity. We expect to fund our growth with cash flow from operations, availability under our senior secured revolving credit facility and debt and equity offerings when appropriate. Consistent with our disciplined approach to financial management, we expect to maintain an active hedging program to protect our cash flow and the funding of our capital program.
Our Strengths
We believe that the following strengths provide us with significant competitive advantages and position us to continue to successfully execute our strategies:
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High quality acreage in the up-dip oil window of the STACK. The geology of the STACK presents numerous liquids-rich targets with large estimated ultimate recoveries per well, which results in very attractive wells and multiple well locations covering a given vertical section. We believe that the up-dip, naturally fractured oil window in eastern Kingfisher County, Oklahoma, where a substantial portion of our acreage is located, is a particularly attractive portion of the STACK. We believe the geology underlying our acreage results in a higher oil component of our production stream relative to the rest of the STACK, which enhances the equivalent per-unit revenue of our production at current commodity prices. The productive areas on our highly contiguous acreage position are located at approximately 4,000 to 8,000 total vertical depth. Our target formations are shallower in eastern Kingfisher County than in other parts of the STACK, which results in significantly lower capital costs and an increase in our return on capital.
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Large, highly contiguous acreage position with multi-year inventory of low-risk horizontal drilling locations. Our acreage in the STACK is characterized by a liquids-weighted inventory of horizontal drilling locations that provides attractive growth opportunities. Our core production area in the STACK has supported production since the 1940s and has a well-established infrastructure from historical operations. Our large, highly contiguous acreage blocks and focus on maintaining operational control provide us the flexibility to adjust our drilling and completion techniques in order to optimize our well results. Additionally, our highly contiguous acreage allows us to leverage existing infrastructure for more cost-efficient development and transportation. Our acreage position in the STACK also provides growth potential from an inventory of identified gross horizontal drilling locations to develop the Osage and Meramec formations, and identified gross horizontal drilling locations to develop the Oswego formation. Based on results from our horizontal drilling program and those of other operators, we believe significant development opportunities exist in other formations in the STACK.
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Substantial experience in the STACK and unconventional drilling techniques. We have owned portions of our current acreage position since 1992 and developed a deep familiarity with STACK geology due to the length of our operating history. Additionally, we have an experienced and technically-adept management team, averaging more than 24 years of industry experience. We have built a strong technical staff of geologists and geophysicists, field operations managers, and engineers. Our technical expertise, coupled with our STACK experience has enabled us to grow proved reserves and production in the STACK since 2012. Our recent focus in the STACK has been to implement a multi-year, multi-rig program to develop the Osage, Meramec and Oswego formations using horizontal drilling and multi-stage hydraulic fracturing technology. Our completion design has increased in number of stages and sand per stage with each new generation of wells. Since early 2013, our completion practices have progressed through four major generations in
completion hardware, hydraulic fracture spacing, fluid selection and proppant loading in order to optimize single-well returns. We have proactively modified completion designs with each generation of new wells, which has led to improved well response.
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Robust midstream infrastructure supports production growth and access to markets. We have relationships with multiple gas gathering and processing companies including DCP Midstream, LLC (“DCP”), Mustang Gas Products, LLC (“Mustang”), EnLink Midstream Partners, LP (“EnLink”), MarkWest Energy Partners, L.P. (“MarkWest”) and Energy Transfer Partners, L.P. (“Energy Transfer”). These companies, in conjunction with Kingfisher, provide the midstream and operational infrastructure necessary to support our drilling schedule and expected production growth. Kingfisher commissioned its system to be “purpose built” to synchronize with our gathering needs, and those of other STACK operators, stemming from the expected horizontal development of our acreage position. The Kingfisher system and plant began operation in the second quarter of 2016, which enhanced our takeaway capacity given our dedicated 60 MMcf/d contracted volume with Kingfisher. Additionally, Kingfisher’s planned 200 MMcf/d plant expansion is under way, and we have contracted for up to 100% of the additional capacity. We believe this will ensure the continuous development of our horizontal inventory.
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Financial strength and flexibility. We have a strong financial position and a prudent financial management strategy, which will allow us to actively allocate capital in order to grow production, reserves and cash flow. We believe our cash flow from operations, along with borrowing capacity and existing cash, will provide us with sufficient liquidity to execute on our 2018 capital program. Additionally, we have an effective hedging program in place to protect our future cash flows and provide more certainty for the budgeting of our capital plan. We plan to continue our hedging program to protect future revenues.
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 interests to be divided into economic units held by the partners referred to as “LP Units” and non-economic general partner interests owned by AMH GP (as defined below) referred to as “GP Units”. AMH GP owns all the GP Units and SRII Opco LP owns all the LP Units.
As a limited partnership, our operations and activities are managed by the board of directors (the “Board of Directors”) of our general partner, AMH GP. The limited liability company agreement of AMH GP provides for two classes of interests: (i) Class A Units, which hold 100% of the economic interests in AMH GP and (ii) Class B Units, which hold 100% of the voting interests in AMH GP. SRII Opco LP is the sole owner of Class A Units and owns 90% of the Class B Units. Harlan H. Chappelle, our Chief Executive Officer and a director, Michael Ellis, the founder, our Chief Operating Officer and Chairman of the Board of Directors and certain affiliates of Bayou City, and Highbridge, own an aggregate 10% of the Class B Units. AMH GP’s Board of Directors are selected by the Class B Members. Notwithstanding the foregoing, voting control of AMH GP is vested in SRII Opco LP pursuant to a voting agreement.
All distributions under our partnership agreement are made to the limited partners pro rata when AMH GP so directs.
Reserve and Production Overview
The following table describes our proved reserves and production profile as of December 31, 2017:
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(1)
Computed as a percentage of total reserves of the area.
(2)
PV-10 was calculated using oil and natural gas price parameters established by current Securities and Exchange Commission (“SEC”) guidelines and accounting rules based on the unweighted arithmetic average of oil and natural gas prices as of the first day of each of the twelve months ended December 31, 2017. Because we are a partnership and, as such, are not subject to income taxes, our PV-10 is the same as our standardized measure of future net cash flows, the most comparable measure under United States generally accepted accounting principles, which is reduced for the discounted value of estimated future income taxes. Calculation of PV-10 does not give effect to derivatives transactions. The unweighted arithmetic average prices as of the
first of each month during the twelve months ended December 31, 2017 were $51.34 per Bbl of oil and $2.98 per MMBtu of natural gas. The estimated realized prices for natural gas liquids using a $51.34 per Bbl benchmark and adjusted for average differentials were $26.06. Natural gas liquid prices vary depending on the composition of the natural gas liquids basket and current prices for various components thereof, such as butane, ethane, and propane, among others.
(3)
Includes developed and undeveloped acreage.
(4)
Calculated as gross wells times our working interest percentage.
(5)
Average daily net production in the year ended December 31, 2017. The average daily net production excludes the Weeks Island field, which we sold during the fourth quarter of 2017. See Note 6 - Discontinued operations for further details.
Our Properties
STACK, Oklahoma
As of December 31, 2017, we have assembled a highly contiguous position of approximately 130,000 net acres largely in the up-dip, naturally-fractured oil portion of the STACK in eastern Kingfisher County, Oklahoma, which makes up about 96% 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.
As of December 31, 2017, we had a 68% average working interest in 608 gross producing wells. We produced 7,513 MBOE net to us from our STACK properties in 2017, an increase of 58% as compared to 4,768 MBOE in 2016. During 2017, we spent approximately $356 million in the STACK for the drilling and completion of wells, as well as other expenditures for facilities and acquisition of leaseholds. For the twelve months ended December 31, 2017, we have received approximately $92.7 million from BCE under our joint development agreement. We currently operate seven drilling rigs in the STACK for horizontal development. We plan to increase to eight drilling rigs by the end of 2018, 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.
Following the closing of the business combination, our capital expenditure budget for 2018 of approximately $568 million is all allocated to the STACK. Additionally, we anticipate that up to an additional $25 million will be funded for 2018 drilling and completions activity in the STACK by BCE pursuant to our joint development agreement (described below). We currently operate seven drilling rigs in the STACK and anticipate increasing to eight drilling rigs by the end of 2018, which will result in drilling a total of approximately 175 gross wells in the STACK.
Bayou City Joint Development Agreement
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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 drilling program will fund the development of 80 additional wells, in four tranches of 20 wells each. As of December 31, 2017, 54 joint wells have been drilled or spudded leaving 26 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 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 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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Market Access
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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, Kingfisher commissioned a 60 MMcf/d cryogenic gas processing facility within our acreage footprint. This facility receives natural gas from the Kingfisher 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. Kingfisher has commenced a 200 MMcf/d expansion that it expects to be operational by end of April 2018.
We have committed the oil and natural gas production from our Kingfisher County acreage, not otherwise committed to others, to Kingfisher. As part of the Kingfisher contract, we have secured firm processing rights of 260 MMcf/d at the expanding Kingfisher 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 Kingfisher contract. On September 21, 2016, we entered into an agreement with Kingfisher that beginning January 1, 2017 through January 31, 2022, we shall reimburse Kingfisher for 50% of any shortfall fee paid by Kingfisher to a third-party operator for any year in which the daily delivered gas volume is less than the daily gas volume committed. Prior to the consummation of the business combination, affiliates of our former Class B limited partner, High Mesa, owned minority equity interests in Kingfisher, as describe more in detail under “Item 13. Certain Relationships and Related Transactions, and Director Independence - Gathering Agreements.”
Other Assets
Through February 8, 2018, we conducted operations in other areas. On February 8, 2018, we distributed the remainder of our non-STACK assets to AM Contributor as a dividend. The remaining non-STACK assets distributed subsequent to year end will be reflected as discontinued operations in future filings when the criteria for discontinued operations for the remaining non-STACK are met under ASC 205-20, “Discontinued Operations”.
Our Oil and Natural Gas Reserves
The table below summarizes our estimated net proved reserves as of December 31, 2017:
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(1)
Our proved reserves as of December 31, 2017 were calculated using oil and natural gas price parameters established by current SEC guidelines and accounting rules based on unweighted arithmetic average prices as of the first day of each of the twelve months ended on such date. These average prices were $51.34 per Bbl for oil and $2.98 per MMBtu for natural gas. The estimated realized price for natural gas liquids using a $51.34 per Bbl benchmark adjusted for average differentials was $26.06. Natural gas liquid prices vary depending on the composition of the natural gas liquids basket and current prices for various components thereof, such as butane, ethane, and propane, among others. Pricing was adjusted for basis differentials by field based on our historical realized prices. See “Note 21 - Supplemental Oil and Natural Gas Disclosures (Unaudited)” in the accompanying notes to consolidated financial statements included elsewhere in this report for information concerning proved reserves.
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 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:
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Over 30 years of practical experience in petroleum engineering and in the estimation and evaluation of reserves;
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Bachelor of Science Degree in Petroleum Engineering from the University of Texas in 1980, Masters of Business Administration from Oklahoma City University in 1988;
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Registered Professional Engineer in Oklahoma.
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:
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no employee’s compensation is tied to the amount of reserves booked;
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we follow comprehensive SEC-compliant internal policies to determine and report proved reserves;
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reserve estimates are made by experienced reservoir engineers or under their direct supervision; and
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each quarter, our Chief Operating Officer and Chief Executive Officer review all significant reserves changes and all new proved undeveloped reserves additions.
Ryder Scott Company, L. P. (“Ryder Scott”), a third party consulting firm, audited 97% of our 2017 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, and 99.2. The qualifications of the technical persons at Ryder Scott primarily responsible for overseeing the audit of our reserve estimates are set forth below.
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 35 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, 2017, we had PUDs of 125.1 MMBOE, or approximately 68% of total proved reserves.
Total PUDs at December 31, 2016 were 98.4 MMBOE, or 71% of our total proved reserves. The following table reflects the changes in PUDs during 2017:
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PUDs converted to proved developed reserves were primarily in the STACK, our most active development area. During 2017, we incurred approximately $26.3 million in expenditures to convert the December 31, 2016 PUDs to proved developed reserves. Extensions and discoveries were due to increases in PUD reserves associated with our successful drilling activity in the STACK. In 2017, we had negative revisions of 3,274 MBOE primarily due to PUD wellbore interest assignments and extension of tranche reversions related to the BCE joint development agreement, which were partially offset by positive price revisions. Estimated future development costs, including plugging and abandonment cost (“P&A”), for PUDs remaining are approximately $978.4 million at December 31, 2017.
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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, 2017 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 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.
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We reevaluate our five year PUD schedule quarterly. However, the relative proportion of total PUD reserves that we develop over the next five years will not be uniform year to year, but will vary by year depending on several factors, including financial targets such as reducing debt and/or drilling within cash flow, drilling obligatory wells (wells where a third-party operator has elected to drill a well and we are faced with either drilling the well or incurring penalties or where we need to drill or recomplete a well to preserve a lease), drilling acreage to hold it with production, and the inclusion of new acquisitions with associated PUDs. When developing our long range plan, we prioritize drilling based on many factors including product prices, capital availability and expected rates of return. As a result, we may drill PUDs with smaller net reserves but with higher returns.
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During 2016 and 2017, we focused on drilling wells to hold our acreage and expand our proved reserves, as opposed to drilling PUD locations for development purposes as most of our PUDs are currently held by production. We anticipate drilling in excess of 170 wells in each of the following five years. At year-end 2017, we had approximately 398 PUD locations in our inventory and, of these locations, approximately 300 are operated by us. During 2018 and 2019, we are only required to drill 30 PUD wells and will begin pattern development as we continue to focus on drilling other wells to expand our proved reserves. By 2020 and 2021, we will need to have drilled 83 and 147 wells, respectively. Accordingly, we anticipate drilling the large majority of our currently booked PUDs in the aggregate before drilling commitments become due in 2020 and 2021.
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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 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”:
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The following table provides a summary of our production, average sales prices and average production costs for the STACK area, which contributes approximately 96% of our total proved reserves as of December 31, 2017;
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Delivery Commitments
As of December 31, 2017, we had no commitments to provide a fixed quantity of oil, natural gas or natural gas liquids.
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Drilling Activity
The following table sets forth, for each of the three years ended December 31, 2017, 2016 and 2015, 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.
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We had one net well that is a developmental dry hole. The well was a recompletion related to our non-STACK assets.
Present Activities
As of December 31, 2017, we were drilling 43 gross (18.0 net) wells.
Productive Wells
The following table sets forth information with respect to our ownership interest in productive wells as of December 31, 2017:
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Of the total well count as of December 31, 2017, 1 gross wells (0.6 net) are multiple completions.
Productive wells are producing wells, shut-in wells we deem capable of production, wells awaiting 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, 2017, all of which is located in the United States:
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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.
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, 2017, 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:
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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) 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, 2017, 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”). Prior to the Closing, we were 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, 2017, revenues marketed by AEM were $199.2 million, or approximately 70.9% of total revenue excluding the Weeks Island field sales marketed by AEM and 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
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.
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.
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 change in the future. In particular, the prices of oil and natural gas declined dramatically after the second half of 2014. 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. Oil prices continued to fluctuate during 2017. Based on daily settlements of monthly contracts traded on the NYMEX, the average price for the twelve months ended December 31, 2017 for a barrel of oil ranged from a high of $57.95 in December 2017 to a low of $45.20 in June 2017, and the price for an MMBtu of natural gas ranged from a high of $3.93 in January 2017 to a low of $2.63 in March 2017.
Continued fluctuations in oil and natural gas prices, 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 2017 was $49.44 per barrel compared to $40.54 per barrel in 2016 and $46.22 per barrel in 2015. 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.
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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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the domestic and foreign supply of and demand for oil and natural gas;
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the price and quantity of foreign imports of oil and natural gas;
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changes in federal regulations removing decades-old prohibition of the export of crude oil production in the U.S.;
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federal regulations applicable to exports of liquefied natural gas (“LNG”), including the recently initiated exports of LNG liquefied from natural gas produced in the lower 48 states of the U.S.;
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actions taken by members of the Organization of Petroleum Exporting Countries and other oil producing nations in connection with their arrangements to maintain oil price and production controls;
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the level of consumer product demand;
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weather conditions;
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domestic and foreign governmental regulations, including environmental initiatives and taxation;
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overall domestic and global economic conditions;
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the value of the dollar relative to the currencies of other countries;
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stockholder activism or activities by non-governmental organizations to restrict the exploration, development and production of oil and natural gas in order to minimize emissions of carbon dioxide, a greenhouse gas (“GHG”);
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political and economic conditions and events in foreign oil and natural gas producing countries, including embargoes, continued hostilities in the Middle East and other sustained military campaigns, conditions in South America, Central America, China and Russia and acts of terrorism or sabotage;
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the proximity and capacity of natural gas pipelines and other transportation facilities to our production;
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technological advances affecting energy consumption;
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the price and availability of alternative fuels; and
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the impact of energy conservation efforts.
Substantially all of our production is sold to purchasers under contracts with market-based prices. Lower oil and natural gas prices will reduce our cash flows and may reduce the present value of our reserves.
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. As a result of the current price environment and in connection with the business combination, we have increased our budgeted capital expenditures for 2018. Our estimated STACK capital expenditures for 2018 are $568 million for the drilling and completion of wells, as well as other expenditures for facilities and acquisition of leaseholds. Our STACK capital expenditures for 2017 and 2016 totaled $356 million and $209 million, respectively, for the drilling and completion of wells, as well as other expenditures for facilities and acquisition of leaseholds. For the twelve months ended December 31, 2017, we have received approximately $92.7 million from BCE under our joint development agreement. 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 and with proceeds we received in the business combination. 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:
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the estimated quantities of our proved oil and natural gas reserves;
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the amount of oil and natural gas we produce from existing wells;
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the prices at which we sell our production; and
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our ability to acquire, locate and produce new reserves.
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 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.
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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:
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landing our wellbore in the desired drilling zone;
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staying in the desired drilling zone while drilling horizontally through the formation;
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running our production casing the entire length of the wellbore; and
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running tools and other equipment consistently through the horizontal wellbore.
The difficulties that we face while completing our wells include the following:
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designing and executing the optimum fracture stimulation program for a specific target zone;
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running tools the entire length of the wellbore during completion operations; and
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cleaning out the wellbore after completion of the fracture stimulation.
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.
Our producing properties are located in a limited geographic area, making us vulnerable to risks associated with having geographically concentrated operations.
Our producing properties are geographically concentrated in the STACK. Because of this concentration, the success and profitability of our operations may be disproportionately exposed to regional factors relative to our competitors that have more geographically dispersed operations. These factors include, among others: (i) the prices of crude oil and natural gas produced from wells in the region and other regional supply and demand factors, including gathering, pipeline and rail transportation capacity constraints; (ii) the availability of rigs, equipment, oil field services, supplies and labor; (iii) the availability of processing and refining facilities; and (iv) infrastructure capacity. In addition, our operations in the STACK may be adversely affected by severe weather events such as floods, ice storms and tornadoes, which can intensify competition for the items described above during months when drilling is possible and may result in periodic shortages. The concentration of our operations in a limited geographic area also increases our exposure to changes in local laws and regulations, certain lease stipulations designed to protect wildlife and unexpected events that may occur in the regions such as natural disasters, seismic events, industrial accidents or labor difficulties. Any one of these events has the potential to cause producing wells to be shut-in, delay operations, decrease cash flows, increase operating and capital costs and prevent development of lease inventory before expiration. Any of the risks described above could have a material adverse effect on our financial condition, results of operations and cash flows.
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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 2018 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 (or imposed forced pooling) of such acreage with adjacent properties controlled by third parties. Our assumptions regarding the impact on any such unitization or forced pooling 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. See “Risk Factors-We may have difficulty maintaining our historic levels of success in using the current Oklahoma forced pooling process to increase our interest 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 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.
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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 decline 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.
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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.
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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 2017 and 2016 of $30.3 million and $16.3 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.
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In the future, we may recognize significant impairments of proved oil and natural gas properties and impairments of unproved oil and natural gas properties as a result of lower forecasted commodity prices and changes to our drilling plans. At December 31, 2017, our estimate of undiscounted future cash flows attributable to our proved oil and natural gas properties with a net book value of approximately $762.2 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 the oil and natural gas prices decline by 10%, this depletion group becomes impaired in a future period and we could recognize non-cash impairments in that period in excess of $2.7 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, 2017. 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.
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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:
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actual prices we receive for crude oil and natural gas;
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actual cost of development and production expenditures;
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the amount and timing of actual production;
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transportation and processing; and
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changes in governmental regulations or taxation.
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, 2017 would decrease by approximately $358.3 million to $747.7 million.
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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 change our development plans to delay the drilling of those wells within the required five-year timeframe.
Approximately 68% of our total estimated proved reserves at December 31, 2017 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, 2017, approximately 125.1 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, 2017 assumed that we would spend $978.4 million, including plugging and abandonment costs, to develop our estimated PUDs, including an estimated $382.7 million during 2018. 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 commodity prices will reduce the future net revenues of our estimated PUDs and may result in some projects becoming uneconomical. As a result of lower oil and natural gas prices, we may reduce the budgeted capital expenditures for the development of undeveloped reserves. 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.
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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:
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increased responsibilities for our executive level personnel;
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increased administrative burden;
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increased capital requirements; and
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increased organizational challenges common to large, expansive operations.
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:
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the results of our drilling program;
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hydrocarbon prices;
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our ability to develop existing prospects;
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our ability to obtain leases or options on properties for which we have 3-D seismic data;
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our ability to acquire additional 3-D seismic data;
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our ability to identify and acquire new exploratory prospects;
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our ability to continue to retain and attract skilled personnel;
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our ability to maintain or enter into new relationships with project partners and independent contractors; and
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our access to capital.
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.
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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.
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.
We have made and may in the future 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 senior secured revolving credit facility and the indenture governing the 2024 Notes impose certain limitations on our ability to enter into mergers or combination transactions. Our 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:
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damages to equipment caused by natural disasters such as earthquakes and adverse weather conditions, including tornadoes and flooding;
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facility or equipment malfunctions;
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pipeline or tank ruptures or spills;
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surface fluid spills, produced water contamination and surface or groundwater contamination resulting from petroleum constituents or hydraulic fracturing chemical additions;
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fires, blowouts, craterings and explosions; and
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uncontrollable flows of oil or natural gas or well fluids.
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.
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:
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delays imposed by or resulting from compliance with regulatory requirements, including limitations resulting from wastewater disposal;
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regulation limiting emission of GHGs and limitations on hydraulic fracturing;
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pressure or irregularities in geological formations;
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shortages of or delays in obtaining equipment and qualified personnel or in obtaining water for hydraulic fracturing activities;
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equipment failures, accidents or other unexpected operational events;
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lack of available gathering facilities or delays in construction of gathering facilities;
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lack of available capacity on interconnecting transmission pipelines;
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adverse weather conditions;
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issues related to compliance with environmental regulations;
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environmental hazards, such as oil and natural gas leaks, oil spills, pipeline and tank ruptures and unauthorized discharges of brine, well stimulation and completion fluids, toxic gases or other pollutants into the surface and subsurface environment;
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declines in oil and natural gas prices;
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limited availability of financing at acceptable terms;
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title problems; and
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limitations in the market for oil and natural gas.
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, 2017, we
have hedged approximately 35% of our total forecasted PDP production through 2020 at weighted average annual floor prices ranging from $50.00 per Bbl to $51.59 per Bbl for oil and $3.60 per MMBtu for natural gas, with the majority of the hedged volumes in 2018. Our senior secured revolving credit facility limits the amount of hedges that we can place on our PDP production. 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.
Our hedging transactions expose us to counterparty credit risk.
Our hedging transactions expose us to risk of financial loss if our 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 declines 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 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.
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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.
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Competition in the oil and natural gas industry is intense, making it more difficult for us to acquire properties, market oil or natural gas and secure trained personnel.
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. Our competitors 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, 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. Our inability to compete effectively with our competitors could have a material adverse impact on our business activities, financial condition and results of operations.
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We may not be able to keep pace with technological developments in the oil and natural gas industry.
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. In such cases, the amount paid for such oil or natural gas lease or leases or other developed rights would be lost. It is the practice of our management, 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 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.
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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 operations 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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CAA, which restricts the emission of air pollutants from many sources, imposes various pre-construction, monitoring and reporting requirements and is relied upon by the EPA as authority for adopting climate change regulatory initiatives relating to GHG emissions;
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the Federal Water Pollution Control Act, also known as the CWA, which regulates discharges of pollutants from facilities to state and federal waters and establishes the extent to which waterways are subject to federal jurisdiction and rulemaking as protected waters of the United States;
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OPA, which imposes liabilities for removal costs and damages arising from an oil spill into waters of the United States;
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SDWA, which ensures the quality of the nations’ public drinking water through adoption of drinking water standards and control over the subsurface injection of fluids into belowground formations;
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RCRA, which imposes requirements for the generation, treatment, storage, transport disposal and cleanup of non-hazardous and hazardous wastes;
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CERCLA, which imposes liability on generators, transporters and arrangers of hazardous substances at sites where hazardous substance releases have occurred or are threatening to occur as well as imposes liability on present and certain past owners and operations of sites were hazardous substance releases have occurred or are threatening to occur;
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the Emergency Planning and Community Right to Know Act, which requires facilities to implement a safety hazard communication program and disseminate information to employees, local emergency planning committees and response departments about toxic chemical uses and inventories;
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the Endangered Species Act (“ESA”), which restricts activities that may affect federally identified endangered and threatened species or their habitats through the implementation of operating limitations or restrictions or a temporary, seasonal or permanent ban on operations in affected areas; and
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NEPA, which requires federal agencies to evaluate major agency actions having the potential to impact the environment and that may require the preparation of environmental assessments or environmental impact statements.
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 operating results.
We may have difficulty maintaining our historic levels of success in using the current Oklahoma forced pooling process to increase our interest 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 interest 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 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 its 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 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 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 FERC, we could be subject to substantial penalties and fines.
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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, 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.
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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.
The EPA requires the reporting of GHG emissions from specified large GHG emission sources, including onshore and offshore oil and natural gas production facilities and onshore oil and natural gas processing, transmission, storage and distribution facilities, which may include facilities we operate. More stringent laws and regulations relating to climate change and GHGs may be adopted and could cause us to incur material expenses to comply.
Both houses of Congress previously considered legislation to reduce emissions of GHGs and many states have adopted or considered measures to reduce GHG emission reduction levels, often involving the planned development of GHG emission inventories and/or cap and trade programs. Most of these cap and trade programs work by requiring major sources of emissions or major producers of fuels to acquire and surrender emission allowances. The adoption and implementation of any legislation or regulatory programs imposing reporting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations or could adversely affect demand for the oil, natural gas and natural gas liquids that we produce.
In the absence of comprehensive federal legislation on GHG emission control, the EPA attempted to require the permitting of GHG emissions; although the Supreme Court struck down the permitting requirements, it upheld EPA’s authority to control GHG emissions when a permit is required due to emissions of other pollutants. The EPA has adopted rules to regulate methane emissions, including from new and modified oil and gas production sources and natural gas processing and transmission sources, and has announced its intention to regulate methane emissions from existing oil and gas sources, although it remains unclear the status of future rulemaking under the new administration. This rule is also the subject of pending appeals. In late 2016, BLM adopted rules governing flaring and venting of methane from existing wells and other facilities on public and tribal lands, which could require additional equipment and emissions controls as well as inspection requirements. These rules have been challenged in court and remain in litigation.
As noted elsewhere in this report, both the EPA and BLM have proposed regulatory changes that would reduce the burdens of the above-described GHG emission regulations on new and existing sources, but it is too recent an event to know for certain the impact of these proposed rule changes. See “Item 1. Business - Environmental and Occupational Safety and Health Matters,” under the caption “Climate Change Regulation and Legislation,” of this report for a description of the applicable laws and regulations affecting this issue.
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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. See “Item 1. Business - Environmental and Occupational Safety and Health Matters,” under the captions “Water Discharges and Subsurface Injections” and “Hydraulic Fracturing,” of this report for a description of the applicable laws and regulations affecting this issue
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, 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. More recently, in December 2016, the OCC Oil and Gas Conservation Division and the Oklahoma Geological Survey released well completion seismicity guidance, which requires operators to take certain prescriptive actions, including an operator’s planned mitigation practices, following certain unusual seismic activity within 1.25 miles of hydraulic fracturing operations. In addition, in February 2017, the OCC’s Oil and Gas Conservation District issued an order limiting future increases in the volume of oil and natural gas wastewater injected belowground into the Arbuckle formation in an effort to reduce the number of earthquakes in the state.
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 we could 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.
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.
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 of our business, such as title, royalty or contractual disputes, regulatory compliance matters and personal injury or property damage matters. 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.
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 are concentrated in the STACK, 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
secured revolving credit facility and the indenture governing the 2024 Notes also contain covenants, that, among other things, limit our ability to:
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incur additional indebtedness;
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sell assets;
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guaranty or make loans to others;
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make investments;
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enter into mergers;
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make certain payments and distributions;
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enter into or be party to hedge agreements;
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amend our organizational documents;
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incur liens; and
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engage in certain other transactions without the prior consent of the lenders.
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 $350.0 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
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:
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refinancing or restructuring our debt;
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selling assets;
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reducing or delaying capital investments; or
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seeking to raise additional capital.
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.
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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.
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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
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 systems. If any 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, and (3) 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, Congress passed tax reform in December of 2017, and that legislation has changes including, but not limited to (1) the elimination of the deduction for U.S. production activities, (2) the provision for individual taxpayers to deduct 20% of their domestic qualified business income (which may provide some relief from the aforementioned item), (3) more stringent limitation on business interest deduction, (4) modification of NOL carryforward rules, and (5) changes to items excluded from the $1.0 million executive compensation deduction limitation. These changes are mostly effective beginning in the tax year 2018, and we have not yet calculated their effect on our forward-looking financials. The further 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.
Item 1B.
Item 1B. Unresolved Staff Comments.
None.
Item 2.
Item 2. Properties
Information regarding our properties is contained in “Item 1. Business” contained herein.
Item 3.
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, 2017, we have accrued approximately $2.5 million ($0.8 million in current liabilities and $1.7 million in other long-term liabilities) in connection with the settlement. The settlement requires payment over the term of six years.
On January 25, 2017, Bollenbach Enterprises Limited Partnership filed a class action petition in Kingfisher County, Oklahoma against Oklahoma Energy Acquisitions, LP, our wholly owned subsidiary, Alta Mesa Services, LP, our wholly owned subsidiary, and us (collectively, the “AMH Parties”) claiming royalty underpayment or non-payment of royalty. The suit alleges that the AMH Parties made improper deductions that resulted in underpayment of royalties on natural gas and/or constituents of the gas stream produced from wells. The case was moved to federal court and stayed by the court pending the parties’ efforts to settle the case. In June 2017, the court administratively closed the case following mediation. Class settlement requires approval of the court after certain lengthy notice periods. As of December 31, 2017, we accrued approximately $4.7 million in accounts payable and accrued liabilities in our consolidated balance sheets in connection with this litigation. The settlement expense is recorded in general and administrative (“G&A”) in our consolidated statement of operations and was paid subsequent to year end.
On March 1, 2017, Mustang Gas Products, LLC (“Mustang”) filed suit in the District Court of Kingfisher County, Oklahoma, against Oklahoma Energy Acquisitions, LP, and eight other entities, including us. Mustang alleges that (1) Mustang is a party to gas purchase agreements with Oklahoma Energy containing gas dedication covenants that burden land, leases and wells in Kingfisher County, Oklahoma, and (2) Oklahoma Energy, in concert with the other defendants, has wrongfully diverted gas sales to us in contravention of these agreements. Mustang asserts claims for declaratory judgment, anticipatory repudiation and breach of contract against Oklahoma Energy only. Mustang also claims tortious interference with contract, conspiracy, and unjust enrichment/constructive trust against all defendants, including us. While we may incur costs or losses in connection with this litigation, we have not accrued a loss contingency because we are currently unable to determine the scope or merit of Mustang’s claim or to reasonably estimate an amount or range of such costs or losses. We believe that the allegations contained in this lawsuit are without merit and intend to vigorously defend ourselves.
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, 2017.
Item 4.
Item 4. Mine Safety Disclosures
Not applicable.
PART II
Item 5.
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 29, 2018, SRII Opco LP and AMH GP held 100% of such interests.
Distributions to our partners are determined by the terms of our partnership agreement. As of December 31, 2017, 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.
Item 6.
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.
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 “Item 1A. 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, 2017, we have assembled a highly contiguous position of approximately 130,000 net acres largely in the up-dip, naturally-fractured oil portion of the STACK in eastern Kingfisher County, Oklahoma. Our drilling locations primarily 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 seven operated horizontal drilling rigs in the STACK with plans to increase to eight rigs by the end of 2018.
The amount of revenue we generate from our operations will fluctuate based on, among other things:
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the prices at which we will sell our production;
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the amount of oil, natural gas and natural gas liquids we produce; and
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the level of our operating and administrative costs.
Commodity prices remain unpredictable. Therefore, we cannot predict with certainty the future prices for the commodities we produce and sell. 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 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. Our industry has been significantly impacted by lower commodity prices in recent years.
Commodity prices remained volatile, but generally increased on average in 2017 relative to 2016 in response to improving supply and demand of oil, natural gas and natural gas liquids and other factors. Oil prices in particular showed significant signs of improvement in early 2018, with NYMEX West Texas Intermediate (“NYMEX WTI”) reaching $66.14 per barrel on January 26, 2018. The NYMEX WTI monthly settlement price averaged approximately $50.95 per Bbl in 2017 as compared to an average price of $43.32 per Bbl in 2016. NYMEX Henry Hub monthly settlement price for natural gas averaged approximately $3.11 per MMBtu in 2017 as compared to a monthly settlement average price of $2.46 per MMBtu in 2016. On March 20, 2018, NYMEX WTI was $63.40 per barrel and NYMEX Henry Hub was $2.68 per MMBtu. 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. Commodity prices remain unpredictable and it is uncertain whether the increase in market prices experienced in recent months will be sustained. If oil, natural gas and natural gas liquids prices decrease, such decrease 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.
We have increased our anticipated capital expenditures for 2018 to $568 million. Additionally, we anticipate that up to an additional $25 million will be funded for 2018 drilling and completions activity in the STACK by BCE pursuant to our joint development agreement. Following the business combination, we have allocated all of our 2018 capital expenditures to develop the STACK. We anticipate operating up to eight drilling rigs by the end of 2018, which will result in drilling a total of approximately 173 gross wells in the STACK.
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 / decrease in the fair value of derivative contracts, as well as the effect of cash settlements of derivative contracts during the period. In 2017, we recognized a net gain on our derivative contracts of $8.3 million, which includes $4.1 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.
Currently, we have hedged approximately 45% of our forecasted production of proved developed producing reserves through 2020 at weighted average annual floor prices ranging from $50.00 per Bbl to $52.22 per Bbl for oil and $2.80 per MMBtu to $2.90 per MMBtu for natural gas. 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 $30.3 million, $16.3 million and $50.4 million during the years ended December 31, 2017, 2016 and 2015, respectively. The 2017 write-downs were primarily due unproved leasehold costs that were either expired or will be expiring where the Company had no plans for future development, downward revisions in proved reserves and higher operating costs related to our non-STACK assets. Our impairments were primarily related to our oil and natural gas properties related to our non-STACK assets.
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In the future, we may recognize significant impairments of proved oil and natural gas properties and impairments of unproved oil and natural gas properties as a result of lower forecasted commodity prices and changes to our drilling plans. At December 31, 2017, our estimate of undiscounted future cash flows attributable to our proved oil and natural gas properties with a net book value of approximately $762.2 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 the oil and natural gas decline by 10%, this depletion group could become impaired in a future period and we could recognize non-cash impairments in that period in excess of $2.7 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. For further information, see “Results of Operations: Year Ended December 31, 2017 v. Year Ended December 31, 2016: 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
Business Combination with Alta Mesa Resources, Inc.
On August 16, 2017, we entered into a Contribution Agreement (the “AM Contribution Agreement”) with Alta Mesa Resources, Inc. (formerly Silver Run Acquisition Corporation II, a Delaware corporation (“AMR”)), High Mesa Holdings, LP, a Delaware limited partnership (the “AM Contributor”), High Mesa Holdings GP, LLC, a Texas limited liability company and the sole general partner of the AM Contributor, Alta Mesa Holdings GP, LLC, a Texas limited liability company and our sole general partner (“AMH GP”), and, solely for certain provisions therein, the equity owners of the AM Contributor. Simultaneous with the execution of the AM Contribution Agreement, AMR entered into (i) a Contribution Agreement (the “KFM Contribution Agreement”) with KFM Holdco,
LLC, a Delaware limited liability company (the “KFM Contributor”), Kingfisher Midstream, LLC, a Delaware limited liability company (“Kingfisher”), and, solely for certain provisions therein, the equity owners of the KFM Contributor; and (ii) a Contribution Agreement (the “Riverstone Contribution Agreement” and, together with the AM Contribution Agreement and the KFM Contribution Agreement, the “Contribution Agreements”) with Riverstone VI Alta Mesa Holdings, L.P., a Delaware limited partnership (the “Riverstone Contributor”).
On February 9, 2018 (the “Closing Date”), we consummated the transactions contemplated by the Contribution Agreements and SRII Opco LP, a Delaware limited partnership (“SRII Opco LP”) acquired (a) (i) all of the limited partner interests in us and (ii) 100% of the economic interests and 90% of the voting interests in AMH GP (with (i) and (ii) collectively, the “AM Contribution”) and (b) 100% of the economic interests in Kingfisher (the “Kingfisher Contribution”). The acquisition of us and Kingfisher pursuant to the Contribution Agreements is referred to herein as the “business combination” and the transactions contemplated by the Contribution Agreements are referred to herein as the “Transactions.”
SRII Opco GP, LLC, a Delaware limited liability company (“SRII Opco GP”), the sole general partner of SRII Opco LP, is a wholly owned subsidiary of AMR. The limited partners of SRII Opco LP are the AM Contributor, the KFM Contributor and the Riverstone Contributor (collectively, the “Contributors”), AMR and certain funds managed by Highbridge. As a result of the Transactions, AMR has obtained control over the management of AMH GP and, consequently, us. AMR is a publicly traded corporation that is not under the control of any person. Prior to the closing of the Transactions, AMH GP, and consequently, us, was controlled by High Mesa and indirectly by our founder and Chief Operating Officer Michael E. Ellis.
Harlan H. Chappelle, our Chief Executive Officer and a director, Michael Ellis, our Chief Operating Officer and a director and certain affiliates of Bayou City Energy Management, LLC, a Delaware limited liability company (“Bayou City”), and HPS Investment Partners, LLC, a Delaware limited liability company (“Highbridge”), continue to own an aggregate 10% voting interest in AMH GP following the closing. These existing owners were a party to a voting agreement with the AM Contributor and AMH GP, pursuant to which they agreed to vote their interests in AMH GP as directed by the AM Contributor. In connection with the closing of the Transactions, the parties amended and restated the voting agreement to include SRII Opco LP as a party and the existing owners agreed to vote their interests in AMH GP as directed by SRII Opco LP and appoint SRII Opco LP as their respective proxy and attorney-in-fact with respect to any voting matters related to their respective interests in AMH GP. The amended and restated voting agreement will continue in force until SRII Opco LP elects to terminate the agreement or, with respect to each existing owner individually, such existing owner no longer owns a voting interest in AMH GP. The closing of the business combination did not constitute a change of control under the indenture governing our 7.875% senior unsecured notes due December 15, 2024 (the “2024 Notes”).
Consideration
Pursuant to the AM Contribution Agreement, at the closing of the Transactions (the “Closing”), the AM Contributor received 138,402,398 common units representing limited partner interests (the “Common Units”) in SRII Opco LP. The AM Contributor also acquired from AMR a number of newly issued shares of non-economic capital stock of AMR, designated as Class C common stock, par value $0.0001 per share (the “Class C Common Stock”), corresponding to the number of Common Units received by the AM Contributor at the Closing.
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In addition to the above, for a period of seven years following the Closing, the AM Contributor will be entitled to receive an aggregate of up to $800 million in earn-out consideration to be paid in the form of Common Units (and acquire a corresponding number of shares of Class C Common Stock) as specified below if the 20-day volume-weighted average price (“20-Day VWAP”) of the Class A Common Stock equals or exceeds the following prices (each such payment, an “Earn-Out Payment”):
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The AM Contributor will not be entitled to receive a particular Earn-Out Payment on more than one occasion and, if, on a particular date, the 20-Day VWAP entitles the AM Contributor to more than one Earn-Out Payment (each of which has not been previously paid), the AM Contributor will be entitled to receive each such Earn-Out Payment. The AM Contributor will be entitled to the earn-out consideration described above in connection with certain liquidity events of AMR, including a merger or sale of all or substantially all of AMR’s assets, if the consideration paid to holders of Class A Common Stock in connection with such liquidity event is greater than any of the above-specified 20-Day VWAP hurdles.
AMR also contributed approximately $554 million in cash to us at the Closing. AMR’s source for these funds was from the sale of its securities to investors in a public offering and in private placements.
Exchange or Redemption of Common Units
Beginning 180 days after the Closing, the AM Contributor will have the right to exchange its Common Units for shares of AMR Class A Common Stock or cash (at AMR’s election). Upon any redemption of Common Units by the AM Contributor, a corresponding number of shares of Class C Common Stock owned by the AM Contributor will be cancelled.
Amended Limited Partnership and Limited Liability Company Agreements
In connection with the closing of the business combination on February 9, 2018, AMH GP and SRII Opco LP entered into a Seventh Amended and Restated Agreement of Limited Partnership of Alta Mesa (the “Seventh Amended Partnership Agreement”). The Seventh Amended Partnership Agreement reflects, among other things, that SRII Opco LP is now the sole limited partner of Alta Mesa.
In addition, on February 9, 2018, the owners of AMH GP entered into a Sixth Amended and Restated Limited Liability Company Agreement of AMH GP (the “Sixth Amended LLC Agreement”), which was amended to, reflect that SRII Opco LP, now the holder of all of the Class A Units (as defined therein) is entitled to 100% of the economic rights with respect to AMH GP, and that SRII Opco LP is now the holder of 90% of the Class B Units (as defined therein) which are entitled to 100% of the voting rights with respect to AMH GP.
As described above, on February 9, 2018, all of the owners of AMH GP entered into an amended and restated voting agreement (the “Voting Agreement”) regarding the voting of their interests in AMH GP.
Appointment and Departure of Directors
In connection with the business combination, Michael A. McCabe, Homer “Gene” Cole, Mickey Ellis, Don Dimitrievich, William W. McMullen and Mark Stoner resigned from the board of AMH GP. Harlan H. Chappelle and Michael E. Ellis remain directors on the board of AMH GP. In connection with the business combination, James T. Hackett was appointed to the board of AMH GP. Our executive management team remains the same, except that Mr. Hackett is now Chairman of the Board.
Distribution of Non-Stack Assets
In connection with the closing of the business combination, we have completed our transition from a diversified asset base composed of a portfolio of conventional assets to an oil and liquids-rich resource play in the STACK. On February 8, 2018, we distributed the remainder of our non-STACK assets to AM Contributor as a dividend. At the time of the disposition, our management estimated the carrying value of our remaining non-STACK assets to be $42.8 million with liabilities of $52.5 million, which liabilities include $44.6 million of asset retirement obligations.
Amended and Restated Senior Secured Revolving Credit Facility
In connection with the closing of the business combination, we entered into the Eighth Amended and Restated Credit Agreement with Wells Fargo Bank, National Association, as the administrative agent (the “Eighth A&R credit facility”). The Eighth A&R credit facility is for an aggregate maximum credit amount of $1.0 billion with an initial $350.0 million borrowing base limit. The Eighth A&R credit facility 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 February 9, 2018, all outstanding balances under our credit facility were paid in full.
For further details of the business combinations please Note 19 - Subsequent Events in the consolidated financial statements.
Weeks Island Sale
During the fourth quarter of 2017, we sold our oil and natural gas assets in the Weeks Island field. Results of operations for the Weeks Island field are reflected as discontinued operations in our consolidated financial statements for all periods presented. See Note 6 - Discontinued Operations to consolidated financial statements for details. Operating revenues and expenses for all periods exclude discontinued operations in the Weeks Island.
Results of Operations
Selected Operating Data. The following table sets forth operating data from continuing operations for the periods presented.
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Results of Operations: Year Ended December 31, 2017 v. Year Ended December 31, 2016
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Revenues
Oil revenues for the year ended December 31, 2017 increased $88.3 million, or 75%, to $206.0 million in 2017 from $117.7 million in 2016. The increase in oil revenue was primarily attributable to higher prices as well as increased production volumes. The average price of oil exclusive of settlements of derivative contracts increased 22% in 2017 resulting in an increase in oil revenues of approximately $37.1 million. The average price inclusive of settlements of derivative contracts decreased 29% from $68.96 per Bbl in 2016 to $49.13 per Bbl in 2017. An increase in production of 1,263 MBbls, or 43% resulted in an approximate $51.2 million increase in oil revenues. The increase in oil volumes is primarily due to new production from the STACK, which increased 1,337 MBbls, from 2,570 MBbls in 2016 to 3,907 MBbls in 2017, partially offset by decreased production from non-STACK fields due to natural decline.
Natural gas revenues for the year ended December 31, 2017 increased $18.1 million, or 61%, to $47.6 million in 2017 from $29.5 million in 2016. The increase in natural gas revenue was attributable to increased production volumes as well as higher prices during 2017. An increase in production of 4.7 Bcf, or 35% resulted in an increase in natural gas revenues of approximately $10.4 million in 2017 as compared to 2016. The increase in natural gas volumes is attributable to new production from the STACK, which increased 5.7 Bcfe, from 8.2 Bcfe in 2016 to 13.9 Bcfe in 2017. This increase was partially offset by decreased production from non-STACK fields due to natural decline. The average price of natural gas exclusive of settlements of derivative contracts increased 20% in 2017 resulting in an increase in natural gas revenues of approximately $7.7 million. The average price inclusive of settlements of derivative contracts increased 12% from $2.69 per Mcf in 2016 to $3.01 per Mcf in 2017.
Natural gas liquids revenues for the year ended December 31, 2017 increased $18.1 million, or 116% to $33.8 million in 2017 from $15.7 million in 2016. The increase in natural gas liquids revenue was primarily attributable to an increase in prices as well as increased volumes. The average price of natural gas liquids exclusive of settlements of derivative contracts increased 49%, from $16.38 per Bbl in 2016 to $24.36 per Bbl in 2017 resulting in an increase in natural gas liquids revenue of $11.0 million. An increase in volumes of 431 MBbls or 45% resulted in an increase in natural gas liquids revenue of $7.1 million in 2017 as compared to 2016. The increase in natural gas liquid volumes is due primarily to an increase in output in the STACK, which increased 454 MBbls, from 823 MBbls in 2016 to 1,277 MBbls in 2017. This increase was partially offset by lower volumes from other non-STACK fields.
Other revenues were $6.0 million during 2017 as compared to $2.6 million during 2016. Other revenues include salt water disposal fees charged to outside working interest owners. The salt water disposal fees were reclassified from lease operating expense. The fees increased from $2.1 million in 2016 to $5.7 million in 2017.
Gain (loss) on sale of assets was a gain of $3.5 million in 2016 as a result of the sale of South Louisiana properties in 2016.
Gain on acquisition of oil and gas properties was a gain of $3.3 million in 2017, primarily related to the acquisitions of proved STACK oil and natural gas properties from Brown and Borelli, et al (“B&B”) and Sentanta Energy, LLC. The bargain purchase gains recognized related to acquisitions which were accounted for as a business combination under ASC 805, Business Combinations during the year ended December 31, 2017 (Refer to Note 4 - Acquisitions and Divestitures, in Item 8 of Part II of this Annual Report on Form 10-K for more information).
Gain (loss) on derivative contracts was a gain of $8.3 million in 2017 inclusive of net derivative settlements received of $4.1 million in 2017 that included a gain of $5.8 million on contracts prior to expiry. This compared to a loss of $40.5 million in 2016 inclusive of net derivative settlements received of $88.7 million in 2016 that included a gain of $64.0 million on contracts prior to expiry. 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 increased $14.5 million to $60.9 million, or 31% in 2017 as compared to $46.4 million in 2016. The increase is primarily due to increased production volume and increased compression, salt water disposal, chemicals, repairs and maintenance and fuel and power totaling $12.4 million. On a per unit basis, lease and plant operating expense decreased 7% from $7.62 to $7.10 per BOE for 2016 and 2017, respectively.
Marketing and transportation expense increased $17.7 million to $30.5 million in 2017 as compared to $12.8 million in 2016. The increase is primarily in the STACK due to increased throughput at the Kingfisher processing facility beginning in the second quarter of 2016. In addition, the increase is due to higher marketing and transportation fee charged to provide effective gathering, efficient processing and assurance that our production will continue to flow as the activity in the basin expands at the Kingfisher processing facility. On a per unit basis, marketing and transportation expense increased from $2.11 to $3.56 per BOE for 2016 and 2017, respectively.
Production and ad valorem taxes increased $3.0 million to $7.2 million, or 73%, for 2017, as compared to $4.2 million for 2016. Production taxes increased $3.0 million primarily due to the increase in oil and natural gas revenues. Ad valorem taxes
remained flat year over year. On a per unit basis, the production and ad valorem taxes increased from $0.68 to $0.84 per BOE for 2016 and 2017, respectively.
Workover expense increased $2.3 million to $5.8 million from $3.5 million for 2017 and 2016, respectively. This expense varies depending on activities in the field and is attributable to many different properties.
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 $0.2 million to $24.6 million in 2017 from $24.8 million in 2016. The decrease in exploration expense is primarily due to decreases in lease rental expenses and G&G seismic expenses of $5.3 million, partially offset by an increase in dry hole expense and settlements of our asset retirement obligations in excess of our estimate of $5.1 million. As of December 31, 2017, our property, plant, and equipment balance includes $2.0 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 $29.5 million to $94.5 million for 2017 as compared to $65.0 million for 2016. On a per unit basis, this expense increased 3% from $10.67 to $11.02 per BOE for 2016 and 2017, respectively. The rate is a function of capitalized costs of proved properties, proved reserves and production by field.
Impairment expense increased $14.0 million to $30.3 million in 2017 from $16.3 million in 2016. 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, development drilling results that were below expectations or high operating costs. Certain undeveloped leasehold costs were impaired as the Company changed its strategic plans on future development in certain areas. The impairments in 2017 were primarily due to write-downs of both unproved oil and natural gas costs and developed fields, primarily in the non-STACK assets. The impairments in 2016 were primarily due to write-downs in developed fields on non-STACK assets, most notably in the Northwest, East Texas and South Louisiana, totaling $15.4 million.
General and administrative expense increased $13.8 million to $55.6 million in 2017 from $41.8 million in 2016. The increase is primarily due to consulting fees attributable to the business combination of approximately $7.7 million, an increase in information technology consulting fees of $1.2 million and settlement expense of $4.2 million. On a per unit basis, general and administrative expenses decreased 6% from $6.86 to $6.48 per BOE for 2016 and 2017, respectively.
Interest expense, net decreased $9.4 million to $50.6 million in 2017 from $60.0 million in 2016. The interest on our senior term loan facility decreased $9.2 million as it was repaid in full during the fourth quarter 2016 and interest on our senior secured credit facility decreased $1.0 million due to a decrease in average outstanding balances during the year. In addition, deferred financing costs associated with the senior term loan facility decreased $1.1 million. The decrease was partially offset by the repurchase and redemption of our $450 million aggregate principal amount of 9.625% senior unsecured notes due 2018 by issuing $500 million aggregate principal amount 7.875% senior unsecured notes due 2024, resulting in an increase in interest expense of $2.1 million.
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.
Loss on discontinued operations was $21.4 million in 2017 as compared to a loss from discontinued operations of $2.3 million in 2016. The increase in the loss on discontinued operations was primarily related to the loss from the sale of assets recognized of $22.2 million.
Results of Operations: Year Ended December 31, 2016 v. Year Ended December 31, 2015
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We entered into derivative contracts for natural gas liquids in the fourth quarter of 2015. The derivative contracts for natural gas liquids became effective in 2016.
Revenues
Oil revenues for the year ended December 31, 2016 decreased $12.3 million, or 9%, to $117.7 million in 2016 from $130.0 million in 2015. The decrease in oil revenue was primarily attributable to lower prices, partially offset by increased production volumes. The average price of oil exclusive of settlements of derivative contracts decreased 12% in 2016 resulting in a decrease in oil revenues of approximately $16.5 million. The average price inclusive of settlements of derivative contracts decreased 10% from $76.39 per Bbl in 2015 to $68.96 per Bbl in 2016. An increase in production of 91 MBbls, or 3% resulted in an approximate $4.2 million increase in oil revenues. The increase in oil volumes is primarily by new production from the STACK, which increased 564 MBbls, from 2,006 MBbls in 2015 to 2,570 MBbls in 2016. This increase was partially offset by decreased volume to the sale of the remainder of our Eagleville properties in the third quarter of 2015 of 430 MBbls and natural production decline related to our non-STACK assets.
Natural gas revenues for the year ended December 31, 2016 increased $3.1 million, or 12%, to $29.5 million in 2016 from $26.4 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 2.9 Bcf, or 28% resulted in an increase in natural gas revenues of approximately $7.4 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 related to our non-STACK assets 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 13% in 2016 resulting in a decrease in natural gas revenues of approximately $4.3 million. The average price inclusive of settlements of derivative contracts decreased 42% from $4.63 per Mcf in 2015 to $2.69 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 $2.6 million during 2016 as compared to $0.7 million during 2015. Other revenues include salt water disposal fees charged to outside working interest owners. The salt water disposal fees were reclassified from lease operating expense. The fees increased from $0.0 million in 2015 to $2.1 million in 2016.
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 $7.4 million to $46.4 million, or 14% in 2016 as compared to $53.8 million in 2015. The decrease is primarily due to a decrease in salt water disposal, repairs and maintenance, and field services, totaling $6.6 million. On a per unit basis, lease and plant operating expense decreased 26% from $10.28 to $7.62 per BOE for 2015 and 2016, respectively.
Marketing and transportation expense increased $9.7 million to $12.8 million in 2016 as compared to $3.1 million in 2015. The increase is primarily in the STACK due to increased throughput at the Kingfisher processing facility beginning in the second quarter of 2016. In addition, the increase is due to higher marketing and transportation fee charged to provide effective gathering, efficient processing and assurance that our production will continue to flow as the activity in the basin expands at the Kingfisher processing facility. On a per unit basis, marketing and transportation expense increased from $0.60 to $2.11 per BOE for 2015 and 2016, respectively.
Production and ad valorem taxes decreased $2.1 million to $4.2 million, or 34%, for 2016, as compared to $6.3 million for 2015. Production taxes decreased $1.6 million primarily due to the decrease in oil revenues. Ad valorem taxes decreased $0.5 million. On a per unit basis, the production and ad valorem taxes decreased from $1.20 to $0.68 per BOE for 2015 and 2016, respectively.
Workover expense decreased $1.7 million to $3.5 million from $5.2 million for 2016 and 2015, respectively. This expense varies depending on activities in the field and is attributable to many different properties.
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 $4.7 million to $24.8 million in 2016 from $29.5 million in 2015. The decrease in exploration expense is primarily due to decreases in dry hole expense and G&G seismic expenses of $11.7 million, partially offset by an increase in expired leasehold and settlements of our asset retirement obligations in excess of our estimates of $7.6 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 $13.0 million to $65.0 million for 2016 as compared to $78.0 million for 2015. On a per unit basis, this expense decreased 28% from $14.89 to $10.67 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 $34.1 million to $16.3 million in 2016 from $50.4 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 related to our non-STACK assets, totaling $15.4 million. The impairments in 2015 were primarily due to write-downs of both unproved oil and natural gas costs and developed fields, primarily in East Texas, the STACK, and South Louisiana, totaling $34.2 million.
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 19% from $8.49 to $6.86 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.
Loss on discontinued operations was $2.3 million in 2016 as compared to a loss from discontinued operations of $157.3 million in 2015. The decreased in the loss on discontinued operations was primarily due to a decrease in impairment expense recognized. Weeks Island field recognized impairment expense of approximately $20,000 during 2016 as compared to $126.3 million during 2015.
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 principal and interest and any amounts owed during the period related to our hedging positions.
Our 2017 capital budget was primarily focused on the development of our STACK properties through exploitation and development. We spent approximately $369.6 million in 2017 on capital expenditures, including acquisitions, of which $356 million was spent in the STACK. The capital expenditures for 2017 reflected our plans to drill wells that were funded through the joint development agreement with BCE. For the twelve months ended December 31, 2017, we have received approximately $92.7 million from BCE under our joint development agreement. We increased our capital budget for 2018 from 2017 levels in response to the improvement in the current commodity price environment. 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.
We funded our 2017 capital expenditures predominantly with cash flows from operations, drilling and completion of capital funded through our joint development agreement with BCE, capital contribution of $200 million by Riverstone and borrowings under our senior secured revolving credit facility. 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. Subsequent to year end and in connection with the closing of the business combination, Alta Mesa Resources contributed an additional $554 million to us.
We expect to fund our capital budget in 2018 and beyond predominantly with cash flows from operations, borrowings under our senior secured revolving credit facility and drilling and completion capital funded through our joint development agreement with BCE. 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 and future 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
We have $500 million in aggregate principal amount of 7.875% senior unsecured notes, or the “senior notes”, due December 15, 2024 which were issued at par by us and our wholly owned subsidiary Alta Mesa Finance Services Corp. (collectively, the “Issuers”) during the fourth quarter of 2016. 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 senior 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 senior 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 senior notes for cash at a redemption price equal to 100% of their principal amount of the senior notes redeemed plus an applicable make-whole premium and accrued and unpaid interest, if any, to the date of redemption. Upon the occurrence of certain kinds of change of control, each holder of the senior notes may require us to repurchase all or a portion of the senior notes for cash at a price equal to 101% of the aggregate principal amount of the senior notes, plus accrued and unpaid interest, if any, to the date of repurchase. On and after December 15, 2019, we may redeem the senior 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 on 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.
Subsequent to year end, the closing of the business combination with Alta Mesa Resources did not constitute as a change of control under the indenture governing the senior notes because certain existing owners of the Company and SRII Opco LP entered into the Voting Agreement with respect to the voting interests in AMH GP. See Note 19 - Subsequent Events to the consolidated financial statements for further detail.
The senior notes are fully and unconditionally guaranteed on a senior unsecured basis by each of our material subsidiaries, subject to certain customary release provisions. 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 senior 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 senior notes.
The senior notes contain certain covenants limiting the Issuers’ ability and the ability of the Restricted Subsidiaries (as defined in the indenture) 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:
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default in any payment of interest on the senior notes when due, continued for 30 days;
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default in the payment of principal of or premium, if any, on the senior notes when due;
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failure by the Issuers or any subsidiary guarantor to comply with its obligations under the indenture;
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default under any mortgage, indenture or instrument under which there may be issued or by which there may be secured or evidenced any indebtedness for money borrowed by the Issuers or restricted subsidiaries;
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certain events of bankruptcy, insolvency or reorganization of the Issuers or restricted subsidiaries; and
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failure by the Issuers or certain subsidiaries that would constitute a payment of final judgment aggregating in excess of $20.0 million.
Senior Secured Revolving Credit Facility
On February 9, 2018, we entered into the Eighth Amended and Restated senior secured revolving credit facility with Wells Fargo Bank, National Association, as the administrative agent (the “Eighth A&R credit facility”). The Eighth A&R credit facility is for an aggregate of $1.0 billion with an initial $350.0 million borrowing base limit. The Eighth A&R credit facility 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.
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As of March 29, 2018, we have no outstanding borrowings under the Eighth A&R and have $13.6 million of outstanding letters of credit reimbursement obligations.
The principal amounts borrowed are payable on the maturity date on February 9, 2023. We have a choice of borrowing in Eurodollars or at the reference rate, with such borrowings bearing interest, payable quarterly for reference rate loans and one month, three month or six month periods for Eurodollar loans. Eurodollar loans bear interest at a rate per annum equal to the rate at the LIBOR, plus an applicable margin ranging from 2.00% to 3.00%. Reference 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 1.00% to 2.00%. The next scheduled redetermination of our borrowing base is on April 1, 2018. The borrowing base may be reduced in connection with the next redetermination of its borrowing base. The amounts outstanding under the Eighth A&R credit facility are secured by first priority liens on substantially all of the Company’s and its material operating subsidiaries’ oil and natural gas properties and associated assets and all of the stock of our material operating subsidiaries that are guarantors of the Eighth A&R credit facility. Additionally, SRII Opco, LP and AMH GP have pledged their respective limited partner interests in us as security for our obligations. If an event of default occurs under the Eighth A&R credit facility, the administrative agent will have the right to proceed against the pledged capital stock and take control of substantially all of our assets and our material operating subsidiaries that are guarantors.
The Eighth A&R 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. The Eighth A&R credit facility permits us to make distributions to any parent entity (i) to pay for reimbursement of third party costs and expenses that are general and administrative expenses incurred in the ordinary course of business by such parent entity or (ii) in order to permit such parent entity to (x) make permitted tax distributions and (y) pay the obligations under the Tax Receivable Agreement (as defined below).
The Eighth A&R credit facility also requires us to maintain the following two financial ratios:
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a current ratio, tested quarterly, commencing with the fiscal quarter ending June 30, 2018, 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
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a leverage ratio, tested quarterly, commencing with the fiscal quarter ending June 30, 2018, of our consolidated debt (other than obligations under hedge agreements) as of the end of such fiscal quarter to its consolidated EBITDAX annualized by multiplying EBITDAX for the period of (A) the fiscal quarter ending June 30, 2018 times 4, (B) the two fiscal quarter periods ending September 30, 2018 times 2 and (C) the three fiscal quarter periods ending December 31, 2018 times 4/3rds and (D) for each fiscal quarter on or after March 31, 2019, EBITDAX times 4/4, of not greater than 4.0 to 1.0.
Cash Flows Provided by Operating Activities
Operating activities (including operating activities from discontinued operations) provided cash of $59.3 million in 2017, as compared to $131.7 million in 2016. Of the $59.3 million and $131.7 million cash provided by operating activities in 2017 and 2016, discontinued operations provided cash of approximately $21.2 million and 27.1 million in 2017 and 2016, respectively. The $72.4 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 $8.4 million in earnings and a negative impact on cash flow. The changes in our working capital accounts used $64.0 million in cash as compared to having provided $23.8 million in cash in 2016.
Operating activities (including operating activities from discontinued operations) provided cash of $131.7 million in 2016, as compared to $144.0 million in 2015. The $12.3 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 $23.8 million in cash as compared to having provided $4.5 million in cash in 2015.
Cash Flows Used in Investing Activities
Investing activities (including investing activities from discontinued operations) used cash of $345.9 million for the year ended December 31, 2017 as compared to $224.3 million for the year ended December 31, 2016. Capital expenditures for property and equipment, including acquisitions used cash of $369.6 million and $225.6 million for the twelve months ended December 31, 2017 and 2016, respectively. In addition, we entered into an interest bearing promissory note receivable with our affiliate Northwest Gas Processing, LLC for approximately $1.5 million in 2017. The cash used for investing activities was partially offset by proceeds from the sale of the Weeks Island field and other assets of approximately $25.2 million.
Investing activities (including investing activities from discontinued operations) used cash of $224.3 million for the year ended December 31, 2016 as compared to $130.4 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.
Cash Flows Provided by Financing Activities
Financing activities provided cash of $283.9 million during 2017 as compared to cash provided of $91.2 million during 2016, an increase of $192.7 million. During 2017, we drew down $76.4 million, net of payments, under our senior secured revolving credit facility and we paid $0.4 million of deferred financing costs related to our senior secured revolving credit facility and senior notes. During 2017, Riverstone was admitted as a limited partner in connection with its $200 million contribution to us. In addition, we received $7.9 million in capital contributions from our former Class B limited partner, High Mesa.
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.
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, 2017, commodity derivative instruments were in place covering approximately 69% of our projected oil production and, approximately 1% of our natural gas production from proved developed properties for 2018. See Note 8 to our consolidated financial statements as of December 31, 2017, “Derivative Financial Instruments,” for further information.
Contractual Obligations
The following table summarizes our contractual obligations as of December 31, 2017:
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(1)
Interest includes interest on the outstanding balance under our senior secured revolving credit facility maturing in 2020, payable quarterly; on the 2024 Notes, payable semiannually; and on the debt to our founder, which is payable with principal, at maturity in 2021. The weighted average rate on our outstanding borrowings as of December 31, 2017 of 5.48% was utilized to calculate the projected interest for our senior secured revolving credit facility. Projected obligation amounts are based on the payment schedules for interest, and are not presented on an accrual basis. On February 9, 2018, and in connection with the closing of the business combination (as described in Note 19 - Subsequent Events), we entered into the Eighth Amended and Restated Credit Agreement with Wells Fargo Bank, National Association, as the administrative agent (the “Eighth A&R credit facility”). The Eighth A&R credit facility extended our maturity date from November 2020 to February 2023. As of February 9, 2018, all outstanding balances under our credit facility were paid in full. In addition, our founder converted the founder notes into equity interests in the AM Contributor immediately prior to the closing of the business combination with AMR.
(2)
The drilling rigs are included at the gross contractual value. Due to our various working interests where the drilling rig contracts will be utilized, it is not feasible to estimate a net contractual obligation. Net payments under these contracts are accounted for as capital additions to our oil and gas properties and could be less than the gross obligation disclosed. The drillings rigs are utilized in drilling wells that may or may not be included as part of our joint development agreement with BCE.
(3)
Represents estimated discounted costs to retire and remove long-lived assets at the end of their operations.
Off-Balance Sheet Arrangements
As of December 31, 2017 we had no guarantees of third-party obligations. Our off-balance sheet obligations include the obligations under operating leases, and the $2.2 million contingent properties payment for properties acquired in 2008 and prior years. We also have bonds posted in the aggregate amount of $17.4 million, primarily to cover future abandonment costs, and $13.6 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 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.
Emerging growth company. We are classified as an “emerging growth company” under the JOBS Act. For as long as we are an emerging growth company, which may be up to five full fiscal years, unlike other public companies, we will not be required to, among
other things: (i) provide an auditor’s attestation report on management’s assessment of the effectiveness of our system of internal control over financial reporting pursuant to Section 404(b) of the Sarbanes-Oxley Act; (ii) comply with any new requirements adopted by the PCAOB requiring mandatory audit firm rotation or a supplement to the auditor’s report in which the auditor would be required to provide additional information about the audit and the financial statements of the issuer; (iii) provide certain disclosures regarding executive compensation required of larger public companies; or (iv) hold nonbinding advisory votes on executive compensation. We will remain an emerging growth company for up to five years, although we will lose that status sooner if we have more than $1.0 billion of revenues at the end of any fiscal year, have more than $700.0 million in market value of our common stock held by non-affiliates measured as of June 30, or issue more than $1.0 billion of non-convertible debt over a three-year period.
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.
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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.
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, 2017 and 2016. 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.
Prior to the Closing, Alta Mesa was 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.
Recent Accounting Pronouncements
In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASU 2014-09”), which seeks to provide a single, comprehensive revenue recognition model for all contracts with customers concerning the recognition, measurement and disclosure of revenue from those contracts. The revenue standard contains principles that an entity will apply to determine the measurement of revenue and timing of when it is recognized. Subsequent to the issuance of ASU 2014-09, the FASB issued various clarifications and interpretive guidance to assist entities with implementation efforts, including guidance pertaining to the presentation of revenues on a gross basis (revenues presented separately from associated expenses) versus a net basis.
ASU 2014-09 and related interpretive guidance will be effective for interim and annual periods beginning after December 15, 2017, except for emerging growth companies that elect to use the extended transition period for complying with any new or revised financial accounting standards pursuant to Section 7(a)(2)(b) of the Securities Act. The standard allows for either full retrospective adoption, meaning the standard is applied to all periods presented in the financial statements, or modified retrospective adoption, meaning the standard is applied only to the most current period presented. As an emerging growth company we have elected to use the extended transition period and as a result, we will be required to adopt the standard during the first quarter of 2019 using the modified retrospective method with a cumulative adjustment to retained earnings as necessary. AMR is also an emerging growth company. It is reasonably possible that AMR could cease to be an emerging growth company by December 31, 2018. We intend to apply push down accounting and reflect AMR’s basis and accounting policies in our financial statements from the date of the business combination. Therefore, we could be required to adopt the standard in the fourth quarter of 2018.
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We are in the process of assessing our contracts and evaluating the impact on the consolidated financial statements. We are continuing to evaluate the provisions of ASU 2014-09 as it relates to certain sales contracts, and in particular, as it relates to disclosure requirements. In addition, we are evaluating the impact, if any, on the presentation of our future revenues and expenses under the new gross-versus-net presentation guidance. We continue to evaluate the impact of these and other provisions of ASU 2014-09 on our accounting policies, changes to relevant business practices, internal controls, and consolidated financial statements.
In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842)(“ASU 2016-02”), 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: (i) a lease liability, which is a lessee's obligation to make lease payments arising from a lease, measured on a discounted basis; and (ii) a right-of-use asset, which is an asset that represents a 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. ASU 2016-02 also requires disclosures designed to provide information on the amount, timing, and uncertainty of cash flows arising from leases. In January 2018, the FASB issued ASU No. 2018-01, Land easement practical expedient for transition to Topic 842 (“ASU 2018-01”), which provides an optional transition practical expedient to not evaluate under Topic 842 existing or expired land easements that were not previously accounting for as leases under Topic 840, Leases. The standard will be effective for interim and annual periods beginning after December 15, 2018 for public companies and annual periods beginning after December 15, 2019 for all other entities, with earlier adoption permitted. In the normal course of business, we enter into operating lease agreements to support our exploration and development operations and lease assets such as drilling rigs, well equipment, compressors, office space and other assets.
At this time, we cannot reasonably estimate the financial impact ASU 2016-02 will have on our financial statements; however, the adoption and impletion of ASU 2016-02 is expected to have a material impact on our consolidated balance sheets resulting in an increase in both the assets and liabilities relating to our operating lease activities greater than twelve months. The adoption is also expected to result in increase in depreciation, depletion and amortization expense, and interest expense and a reduction in rent expense recorded on our consolidated statement of operations, and additional disclosures. As part of our assessment to date, we have formed an implementation work team and will complete our evaluation in 2018. As we continue to evaluate and implement the standard, we plan to provide additional information about the expected financial impact at a future date. As an emerging growth company we have elected to use the extended transition period and as a result, we will be required to adopt the standard during 2020. AMR is also an emerging growth company. It is reasonably possible that AMR could cease to be an emerging growth company by December 31, 2018. We intend to apply push down accounting and reflect AMR’s basis and accounting policies in our financial statements from the date of the business combination. Therefore, we could be required to adopt the standard on January 1, 2019.
In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments (“ASU 2016-15”), 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 and interim periods within those fiscal years beginning after December 15, 2017 for public companies and for fiscal years beginning after December 15, 2018 for all other entities. As an emerging growth company we have elected to use the extended transition period and as a result, we will be required to adopt the standard during 2019. AMR is also an emerging growth company. It is reasonably possible that AMR could cease to be an emerging growth company by December 31, 2018. We intend to apply push down accounting and reflect AMR’s basis and accounting policies in our financial statements from the date of the business combination. Therefore, we could be required to adopt the standard in the fourth quarter of 2018. The adoption of this guidance will not impact our financial position or results of operations but could result in presentation changes on our consolidated statements of cash flows.
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 for public companies and annual periods beginning after
December 15, 2018 for private companies, and is required to be adopted using a retrospective approach, with early adoption permitted. We early adopted ASU 2016-18 in the fourth quarter of 2017. See Note 2 - Summary of significant accounting policies for further details.
In January 2017, the FASB issued ASU No. 2017-01, Clarifying the Definition of a Business (“ASU 2017-01”), 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 interim and annual periods after December 15, 2017 for public companies and annual periods beginning after December 15, 2018 for all other entities. The amendments should be applied prospectively on or after the effective date and disclosures are not required at transition. Early adoption is permitted for transactions for which the acquisition date occurs before the issuance date or effective date of the amendments, only when the transaction has not been reported in financial statements that have been issued or made available for issuance. The Company early adopted ASU 2017-01 in the fourth quarter of 2017. The adoption of ASU 2017-01 did not have a material impact on our consolidated financial statements; however these amendments could result in the recording of fewer business combinations in the future periods.
Item 7A.
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, 2017, we have hedged approximately 35% of our forecasted production from proved developed reserves through 2020 at average annual floor prices ranging from $50.00 per Bbl to $51.59 per Bbl for oil and $3.60 for natural gas. Forecasted production from proved reserves is estimated in our December 2017 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, 2017 was a net liability of $20.2 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 $25.0 million (decrease in value) or $28.7 million (increase in value), respectively, as of December 31, 2017.
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 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 $1.2 million, based on the balance outstanding at December 31, 2017.
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, 2017 or 2016. 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.
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 in Part IV, Item 15 of this annual report and are incorporated herein by reference.
Item 9.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
Item 9A.
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, 2017 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, 2017. 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 collusion 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, 2017, 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, 2017 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
Item 9B.
Item 9B. Other Information
None.
PART III
Item 10.
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, AMH GP, and the officers and employees of Alta Mesa Services, an entity wholly owned by us. References to our directors are references to the directors of AMH GP. 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 James T. Hackett. 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 “Item 1A. 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 March 15, 2018. Members of our Board of Directors are elected for one-year terms.
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*In connection with the closing of the business combination, Michael A. McCabe, Homer “Gene” Cole, Mickey Ellis, Don Dimitrievich, William W. McMullen and Mark Stoner resigned from our Board of Directors. In connection with the business combination, James T. Hackett was appointed to our Board of Directors
The following is a biographical summary of the business experience of these directors and executive officers:
James T. Hackett became our chairman of the board of directors immediately following the closing of the business combination. He has previously served as Chief Executive Officer and director of AMR since March 2017. Mr. Hackett is a partner at Riverstone. Prior to joining Riverstone in 2013, Mr. Hackett served as the Chairman of the Board from 2006 to 2013 and the Chief Executive Officer from 2003 to 2012 of Anadarko Petroleum Corporation. Before joining Anadarko, Mr. Hackett served as President and Chief Operating Officer of Devon Energy Corporation, following its merger with Ocean Energy, where he had served as Chairman, President, and Chief Executive Officer. Mr. Hackett has held senior positions at Seagull, Duke Energy, and Pan Energy. He also held positions in engineering, finance and marketing in the midstream, oil field services, and power sectors of the energy industry. Mr. Hackett serves on the Board of Directors of Enterprise Products Holdings, LLC, Fluor Corporation (NYSE: FLR), National Oilwell Varco, Inc. (NYSE: NOV), Sierra Oil and Gas and Talen Energy Corporation and Crimson Resources. Mr. Hackett is a former Chairman of the Board of the Federal Reserve Bank of Dallas. Mr. Hackett received a Bachelor of Science degree from the University
of Illinois in 1975 and an MBA and MTS from Harvard Business School in 1979 and 2016, respectively. Mr. Hackett was selected to serve on the board of directors due to his significant leadership experience and his extensive experience in the energy industry.
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. Mr. Chappelle’s experience as our Chief Executive Officer since 2004 and over 30 years of experience in the oil and gas industry uniquely qualify him to serve on our board of directors.
Michael E. Ellis founded Alta Mesa in 1987 after beginning his career with Amoco, and is our Director 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’ experience in management, engineering, exploration and acquisitions and divestitures. Mr. Ellis holds a Bachelor of Science in Civil Engineering from West Virginia University. Because of his broad knowledge of, and experience with, oil and gas exploration and production, we believe Mr. Ellis is well qualified to serve on our board of directors.
Michael A. McCabe, our CFO as well as a Vice President, joined Alta Mesa in September 2006. Mr. McCabe has over 25 years of corporate finance experience, with a focus on the energy industry. 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 of 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. 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.
Ronald J. Smith began working for Alta Mesa in 2008 as the Controller and has been Chief Accounting Officer since 2015. Mr. Smith has over 35 years of accounting experience, primarily in the energy industry. Mr. Smith has served in numerous senior level management positions including positions with Calpine Corporation and Mariner Energy. Mr. Smith holds a Bachelor of Science in Accounting from Robert Morris University, an MBA in Finance from the University of Houston and is a Certified Public Accountant.
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.
Item 11. Executive Compensation
Compensation Discussion and Analysis
This Compensation Discussion and Analysis, describes the material elements of compensation for our named executive officers (“NEOs”) for 2017.
Objectives of Our Compensation Program
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.
Our executive compensation program is intended to motivate our executive officers to achieve strong financial and operating results. In addition, our program is designed to achieve the following objectives:
·
attract and retain highly qualified executive officers by providing reasonable total compensation levels competitive with that of executives holding comparable positions in similarly situated organizations;
·
provide total compensation that is justified by individual performance; and
·
reward our executives for their contributions to our overall performance as well as for their individual performance.
What Our Compensation Program is Designed to Reward
Our strategy is to enhance enterprise value by increasing reserves, cash flow and production in an economically efficient manner by optimizing our drilling and completion techniques. 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 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 primarily of the following elements: base salary, cash bonus, long-term incentives and benefits.
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. Following the closing of the business combination, we have ceased issuing PARs.
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. Following the closing of the business combination, we have ceased offering the deferred compensation plan.
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 2017 compensation.
Messrs. Ellis, Chappelle, McCabe, and Murrell are parties to employment agreements with Alta Mesa Services, L.P., a wholly owned subsidiary of ours (“Alta Mesa Services”). The employment agreements automatically renew annually, subject to prior notice of cancellation by Alta Mesa Services or the executive. These employment agreements establish minimum base salaries for the 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 only 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 2017, the Board of Directors set the base salaries for Messrs. Ellis, Chappelle and McCabe at $485,000, $485,000 and $435,000, respectively, which were unchanged from their 2016 base salaries. In addition, the Board of Directors determined Mr. Murrell’s and Mr. Cole’s salaries of $360,000 and $350,000 for 2017 were appropriate, which were unchanged from their 2016 base salaries.
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 2017 has not yet been determined. No bonuses were paid in 2017 for 2016 performance. However, bonuses paid in 2016 for 2015 performance ranged from approximately 45% to 85% of base salary.
Long-Term Incentives. 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 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 determines 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 million provided that such event also qualifies as a change in control event under Section 409A. The value of the accelerated PARs that vested upon the closing of the business combination was approximately $10.6 million. We will not issue any additional PARs following the closing of the business combination.
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 the Company.
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 the Company minus $400 million. 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 an equity holder of our Company or of a subsidiary in respect of any PARs.
In 2017 and 2016, the Board awarded 20,000 PARs and 15,000 PARs, respectively, to David Murrell. The SIDV of the 20,000 PARs and 15,000 PARs granted is $40 per unit and vests over a five-year period. In 2016, the Board awarded 60,000 PARs to
Michael A. McCabe and 40,000 PARs to Homer “Gene” Cole, respectively. The SIDV of the awards are $40 per unit and vests over a five-year period. Payout of the 2017 and 2016 PARs is based on the increase of the designated value of the PARs over the SIDV of the PARs as determined 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.
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 January 1, 2017, we made an elective employer contribution 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. The Board of Directors elected to make this contribution 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.
Other Compensation. As part of his employment agreement, we provided Mr. McCabe an apartment near our headquarters and paid his commuting expenses to and from his permanent home to Houston, Texas. In March 2017, Mr. McCabe moved his permanent residence to Houston, Texas. Such housing and commuting expense prior to his permanent move totaled approximately $30,652 in 2017. Prior to Mr. McCabe’s permanent move, 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 was outside of the Houston, Texas 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 emphasizes “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
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, vested PARs expire regardless of whether or not there is a payment relating thereto. We consider the possibility of payment at a fixed determination date absent the occurrence of a Liquidity Event to be remote as liquidity has not yet occurred. Therefore, we have not provided any amount for this contingent liability in our consolidated financial statements at December 31, 2017 or 2016. The closing of the business combination resulted in payments to the holders of the PARs. The value of the accelerated PARs that vested upon the closing of the business combination was approximately $10.6 million. We will not issue any additional PARs following the closing of the business combination.
Section 162(m) of the Code. Generally, Section 162(m) of the Code disallows a tax deduction to any publicly-held corporation for individual compensation in excess of $1.0 million paid in any taxable year to certain of our current or former executive officers. As
we were not publicly traded during 2017, our Board of Directors and compensation committee did not take the deductibility limit imposed by Section 162(m) into consideration in setting compensation.
We reserve the right to use our judgment to authorize compensation payments that do not comply with the exemptions in Section 162(m) when we believe that such payments are appropriate and in the best interest of the stockholders, after taking into consideration changing business conditions or the executive’s individual performance and/or changes in specific job duties and responsibilities.
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Section 409A of the Code. We have structured our compensation program in a manner intended 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.
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, 2017, 2016 and 2015. None of the NEOs participate in a defined benefit pension plan.
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(1)
Bonuses for 2017 have not yet been determined.
(2)
Mr. Chappelle’s other compensation for the year ended December 31, 2017 consists of $1,581,250 in an elective contribution made by us to his Retirement Plan account, $11,192 in his matching funds to his 401(k) account, $18,825 in auto expenses, and approximately $3,474 for club membership. Mr. Chappelle’s other compensation for the year ended December 31, 2016 consists of $1,375,000 in an elective contribution made by us to his Retirement Plan account, $11,192 in his matching funds to his 401(k) account, $32,827 in auto expenses, and approximately $4,637 for club membership. Mr. Chappelle’s other compensation for the year ended December 31, 2015 consists of $8,954 in his matching funds to his 401(k) account, $30,131 in auto expenses, and approximately $3,470 for club membership.
(3)
Mr. Ellis’ other compensation for the year ended December 31, 2017 consists of $706,250 in an elective contribution made by us to his Retirement Plan account, $13,250 in matching funds to his 401(k) account and $14,242 in auto expenses. Mr. Ellis’ other compensation for the year ended December 31, 2016 consists of $875,000 in an elective contribution made by us to his Retirement Plan account, $13,250 in matching funds to his 401(k) account and $12,030 in auto expenses. Mr. Ellis’ other compensation for the year ended December 31, 2015 consists of $10,600 in matching funds to his 401(k) account and $9,823 in auto expenses.
(4)
For the year ended December 31, 2017, Mr. McCabe’s other compensation consists of $562,500 in an elective contribution made by us to his Retirement Plan account, $11,042 in matching funds to his 401(k) account, $13,273 in auto expenses and $30,652 in travel and living expenses, which includes $28,384 for an apartment in Houston, Texas and $2,268 for travel, which consists primarily of airfare and the parking. In March 2017, Mr. McCabe moved his permanent residence to Houston, Texas. The Company paid $101,040 for relocation expenses. In 2014, an elective employer contribution was made for the account of Mr. McCabe for $3,000,000 that was fully vested and distributed in 2017. For the year ended December 31, 2016, Mr. McCabe’s other compensation consists of $750,000 in an elective contribution made by us to his Retirement Plan account, $8,270 in matching funds to his 401(k) account, and $89,078 in travel and living expenses, which includes $41,735 for an apartment in Houston, Texas and $47,343 for travel, which consists primarily of airfare and the cost of a leased car and parking. For the year ended December 31, 2015, Mr. McCabe’s other compensation consists of $8,319 in matching funds to his 401(k) account, and $117,776 in travel and living expenses, which includes $41,049 for an apartment in Houston, Texas and $76,727 for travel, which consists primarily of airfare and the cost of rental cars and parking.
(5)
Mr. Murrell’s other compensation for the year ended December 31, 2017 consists of $300,000 in an elective contribution made by us to his Retirement Plan account, $13,500 in matching funds to his 401(k) account, and $3,404 in auto expense. Mr. Murrell’s other compensation for the year ended December 31, 2016 consists of $275,000 in an elective contribution made by us to his Retirement Plan account, $13,250 in matching funds to his 401(k) account, and $5,913 in auto expense. Mr. Murrell’s
other compensation for the year ended December 31, 2015 consists of $10,600 in matching funds to his 401(k) account and $4,219 in auto expense.
(6)
Mr. Cole’s other compensation for the year ended December 31, 2017 consists of $500,000 in an elective contribution made by us to his Retirement Plan account, $13,500 in matching funds to his 401(k) account, $17,724 in auto expense and $5,741 for club membership. Mr. Cole’s other compensation for the year ended December 31, 2016 consists of $450,000 in an elective contribution made by us to his Retirement Plan account, $13,250 in matching funds to his 401(k) account and $16,699 in auto expense. Mr. Cole’s other compensation for the year ended December 31, 2015 consists of $9,692 in matching funds to his 401(k) account and $10,679 in auto expense.
(7)
In 2017 and 2016, the Board awarded 20,000 PARs and 15,000 PARs, respectively, to Mr. Murrell. The SIDV of the 20,000 PARs and 15,000 PARs granted is $40 per unit and vests over a five-year period. In 2016, the Board awarded 60,000 PARs to Mr. McCabe and 40,000 PARs to Mr. Cole, respectively. The SIDV of the awards are $40 per unit and vests over a five-year period. Payout of the 2017 and 2016 PARs is based on the increase of the designated value of the PARs over the SIDV of the PARs as determined 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.
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, Texas. In March 2017, Mr. McCabe moved his permanent residence to Houston, Texas.
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.
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 2017
There were no grants of plan-based awards to our NEOs during the fiscal year ended December 31, 2017.
Outstanding Equity Awards Value at 2017 Fiscal Year-End
There were no outstanding equity awards for our NEOs as of December 31, 2017.
Option Exercises and Equity Awards Vested for Fiscal Year 2017
There were no exercises of equity awards and no vesting of equity awards for our NEOs during fiscal 2017.
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 2017.
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(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 2017, no amounts of salary or bonus were elected to be deferred under the Retirement Plan by any NEO. In 2017, we made elective employer contributions to the accounts for all of our NEOs. The Board of Directors elected to make the contributions for Messrs. Chappelle, Ellis, and McCabe subject to a five-year vesting schedule, with 20% vested each subsequent year. The contributions for Messrs. Murrell and Cole were 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 2014, one elective employer contribution was made for the account of Mr. McCabe. The elective contribution was fully vested and distributed in 2017 in accordance with the terms of the Retirement Plan.
As of fiscal year end 2017, we considered the possibility of payment with respect to outstanding PARs absent the occurrence of a Liquidity Event to be remote as liquidity has not yet occurred. Therefore, no accumulated benefits under the PARs Plan for 2017 has been included. For a description of the PARs Plan, please see the section above entitled “How We Determine Each Element of Compensation-Long-Term Incentives.
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 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, 2017. In presenting this disclosure, we describe amounts earned through December 31, 2017 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, we estimate 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. Additionally, upon termination of employment for any reason, the executive will become 100% fully vested in (1) the unvested portion of any outstanding equity grants held by the executive as of his termination date, and (2) any unvested amounts accrued under any nonqualified deferred compensation or incentive plan or program in which the executive was participating as of his termination date. We expect that the employment agreements will be amended in connection with Closing to remove this accelerated vesting provision.
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 or 18 months’ base salary for Mr. Murrell and two times the annual bonus paid to the executive in the prior year. Assuming termination as of December 31, 2017, 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 in accordance with the Retirement Plan. Assuming termination as of December 31, 2017, Mr. Chappelle, Mr. Ellis, Mr. McCabe and Mr. Murrell would have received a distribution of $866,250, $491,250, $412,500 and $393,750, respectively. 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, 2017, 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, $9,510 for Mr. McCabe, and $20,830 for Mr. Murrell.
“Cause” means:
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the executive’s conviction by a court of competent jurisdiction of a crime involving moral turpitude or a felony, or entering the plea of nolo contendere to such crime by the executive;
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the commission by the executive of a demonstrable act of fraud, or a misappropriation of funds or property, of or upon us or any affiliate;
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the engagement by the executive without approval of us and the Board of Directors in any material activity which directly competes with the business of us or any affiliate or which would directly result in a material injury to the business or reputation of us or any affiliate (including the partners of Alta Mesa); or
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the breach by the executive of any material provision of the employment agreement, and the executive’s continued failure to cure such breach within a reasonable time period set by us but in no event less than twenty calendar days after the executive’s receipt of such notice.
“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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the demotion or reduction in title or rank of the executive, or the assignment to the executive of duties that are materially inconsistent with the executive’s current positions, duties, responsibilities and status with us, or any removal of the executive from, or any failure to re-elect the executive to, any of such positions (other than a change due to the executive’s disability or as an accommodation under the Americans with Disabilities Act), except for any such demotion, reduction, assignment, removal or failure that occurs in connection with (i) the executive’s termination of employment for cause, disability or death, or (ii) the executive’s prior written consent;
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the reduction of the executive’s annual base salary or bonus opportunity as effective immediately prior to such reduction without the prior written consent of the executive; or
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a relocation of the executive’s principal work location to a location in excess of 50 miles from its then current location.
“Retirement” means the termination of the executive’s employment for normal retirement at or after attaining age 70, provided that the executive has been an active employee 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” in the same manner 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 Retirement 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.
Compensation of Executive Officer and Directors after the Business Combination
Employment Agreements, Annual Base Salaries and Target Bonuses
AMR’s Board approved an annual base salary for Mr. Hackett of $520,000, effective on the Closing Date, and a target annual bonus amount under an annual performance bonus program for 2018 of 95% of his annual base salary.
In addition, on the Closing Date, AMR, Alta Mesa and Alta Mesa Services entered into new employment agreements with each of Messrs. Chappelle, Ellis, McCabe, Cole, Murrell and Smith. The employment agreements supersede each executive’s previous employment agreement with Alta Mesa and are for terms of three years (or two years for Mr. Smith).
Mr. Chappelle’s employment agreement entitles him to receive an annual base salary of $830,000 and to participate in an annual performance bonus program with a target bonus award determined by AMR’s Board. For 2018, Mr. Chappelle’s target annual bonus amount under this program will be 125% of his annual base salary. Mr. Chappelle is also entitled to receive an annual physical and reimbursement of up to $5,000 per year for tax planning services. If AMR terminates Mr. Chappelle’s employment without cause or he resigns for good reason, within the meaning of and under his employment agreement, Mr. Chappelle will be entitled to receive (i) a prorated annual bonus for the year of termination, determined based on satisfaction of performance criteria prorated for the partial performance period, (ii) full accelerated vesting of all AMR equity awards that are subject to time-based vesting, accelerated vesting of any AMR equity awards that are subject to performance-based vesting at the target level of performance and full accelerated
vesting of any nonqualified deferred compensation account balance or benefit, (iii) a lump-sum payment equal to the sum of $40,000 for outplacement services, two years of his annual base salary and two times the greater of his target annual bonus and the annual bonus paid to him for the prior year and (iv) payment for up to 18 months of his premiums for continued coverage in AMR’s group health plans and, thereafter, continued participation in AMR’s group health plans at his cost for up to an additional 18 months. Mr. Chappelle is also entitled to receive the amounts under clauses (i), (iii) and (iv) of the preceding sentence if his employment terminates due to his death or disability, under and within the meaning of his employment agreement. If Mr. Chappelle’s qualifying employment termination occurs during the twenty-one months following a change in control (within the meaning of the employment agreement) or, only in the case of termination without cause or resignation for good reason, during the three months prior to a change in control and is demonstrated to be in connection with the change in control, then in addition to the foregoing payments and benefits, Mr. Chappelle will be entitled to an additional lump-sum payment equal to the sum of one year of his annual base salary and one times the greater of his target annual bonus and the annual bonus paid to him for the prior year. Mr. Chappelle’s right to receive termination payments and benefits, other than a prorated annual bonus for the year of termination, is conditioned upon his executing a general release of claims in our favor. Mr. Chappelle has also agreed to refrain from competing with AMR or soliciting its customers or employees during and for a period of 12 months following his employment with AMR.
The employment agreements for Messrs. Ellis, McCabe, Cole, Murrell and Smith entitle them to receive annual base salaries of $520,000, $450,000, $450,000, $360,000, and $270,000, respectively, and to participate in an annual performance bonus program with a target bonus award determined by AMR’s Board. For 2018, Mr. Ellis’s, Mr. McCabe’s and Mr. Cole’s target annual bonus amounts under this program will be 95% of their respective annual base salaries, and Mr. Murrell’s and Mr. Smith’s target annual bonus amounts under this program will be 65% of their respective annual base salaries. Each of Messrs. Ellis, McCabe, Cole, Murrell and Smith is also entitled to receive an annual physical and reimbursement of up to $5,000 per year for tax planning services. If AMR terminates Mr. Ellis’s, Mr. McCabe’s, Mr. Cole’s, Mr. Murrell’s or Mr. Smith’s employment without cause or he resigns for good reason, within the meaning of and under his employment agreement, he will be entitled to receive (i) a prorated annual bonus for the year of termination, determined based on satisfaction of performance criteria prorated for the partial performance period, (ii) full accelerated vesting of all AMR equity awards that are subject to time-based vesting, accelerated vesting of any AMR equity awards that are subject to performance-based vesting at the target level of performance and full accelerated vesting of any nonqualified deferred compensation account balance or benefit, (iii) a lump-sum payment equal to the sum of $24,000 (or $20,000 for Mr. Smith) for outplacement services, 18 months (or 12 months for Mr. Smith) of his annual base salary and 1.5 times (or one times for Mr. Smith) the greater of his target annual bonus and the annual bonus paid to him for the prior year and (iv) payment for up to 18 months of his premiums for continued coverage in AMR’s group health plans and, thereafter, for Messrs. Ellis, McCabe, Cole and Murrell, continued participation in AMR’s group health plans at his cost for up to an additional 6 months. Messrs. Ellis, McCabe, Cole, Murrell and Smith would each also be entitled to receive the amounts under clauses (i), (iii) and (iv) of the preceding sentence if his employment terminates due to death or disability, under and within the meaning of his employment agreement. If Mr. Ellis’s, Mr. McCabe’s, Mr. Cole’s, Mr. Murrell’s or Mr. Smith’s qualifying termination of employment occurs during the fifteen months following a change in control (within the meaning of his employment agreement) or, only in the case of termination without cause or resignation for good reason, during the three months prior to a change in control and is demonstrated to be in connection with the change in control, then in addition to the foregoing payments and benefits, he will be entitled to an additional lump-sum payment equal to the sum of six months of his annual base salary and 0.5 times the greater of his target annual bonus and the annual bonus paid to him for the prior year. Mr. Ellis’s, Mr. McCabe’s, Mr. Cole’s, Mr. Murrell’s and Mr. Smith’s rights to receive termination payments and benefits, other than a prorated annual bonus for the year of termination, are conditioned upon executing a general release of claims in our favor. Each of Messrs. Ellis, McCabe, Cole, Murrell and Smith has also agreed to refrain from competing with AMR or soliciting its customers or employees during and for a period of 12 months following his employment with AMR.
The employment agreements for Messrs. Chappelle, Ellis, McCabe, Cole, Murrell and Smith further entitle them, if a termination of employment occurs during the three years (or two years for Mr. Smith) following the Closing Date, to payment for any excise taxes imposed under Section 4999 of the Internal Revenue Code as a result of a change in control (within the meaning of their respective employment agreements) other than the business combination plus an additional amount that puts the executive in the same after-tax position he would have been absent the imposition of excise taxes under Section 4999 of the Internal Revenue Code.
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Item 12.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
The following table sets forth as of March 28, 2018 the limited partnership interests in Alta Mesa beneficially owned by:
·
all persons who, to the knowledge of our management team, beneficially own more than 5% of our outstanding limited partnership interests;
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each current director of AMH GP;
·
each executive officer of AMH GP named in the Summary Compensation Table; and
·
all current directors and executive officers of AMH GP as a group.
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(1)
Unless otherwise indicated, each of the persons listed in the table may be deemed to have solve voting and dispositive power with respect to such shares and the address for all beneficial owners in this table is at 15021 Katy Freeway, Suite 400, Houston, Texas 77094.
(2)
SRII Opco LP owns 100% of the economic interests in Alta Mesa and AMH GP. BCE-AMH Holdings, LLC, BCE-MESA Holdings, LLC, Mezzanine Partners II Delaware Subsidiary, LLC, Offshore Mezzanine Partners Master Fund II, L.P., Institutional Mezzanine Partners II Subsidiary, L.P., AP Mezzanine Partners II, L.P., The Northwestern Mutual Life Insurance Company, The Northwestern Mutual Life Insurance Company For its Group Annuity Separate Account, Northwestern Mutual Capital Strategic Equity Fund III, LP, KCK-AMIH, Ltd., United Insurance Company of America, Jade Real Assets Fund, L.P., Michael E. Ellis and Harlan H. Chappelle (collectively, the “Existing Owners”) own a 10% non-voting interest in AMH GP. The Existing Owners and AMH GP are parties to a voting agreement with SRII Opco LP pursuant to which the Existing Owners agreed to vote their interests in AMH GP as directed by SRII Opco LP and appoint SRII Opco LP as their respective proxy and attorney-in-fact with respect to any voting matters related to their respective interests in AMH GP.
(3)
SRII Opco GP, LLC owns a non-economic general partner interest in SRII Opco, LP.
(4)
Alta Mesa Resources, Inc. owns a 44.2% limited partnership interest in SRII Opco, LP and 100% of SRII Opco GP, LLC.
(5)
The sole general partner of High Mesa Holdings, LP (the “Alta Mesa Contributor”) is High Mesa Holdings GP, LLC (“High Mesa GP”). High Mesa, Inc. (“High Mesa”) holds a majority of the outstanding limited partner interests in the Alta Mesa Contributor and all of the outstanding limited liability company interests in High Mesa GP. The interests of the Alta Mesa Contributor are beneficially owned (either directly or through interests in High Mesa) by three groups, each consisting of affiliated parties: (i) AM MME Holdings, LP, Galveston Bay Resources Holdings, LP, Petro Acquisitions Holdings, LP, Petro Operating Company Holdings, Inc., Harlan H. Chappelle, Gene Cole, Mike McCabe, Dale Hayes, AM Equity Holdings, LP and MME Mission Hope, LLC (collectively, the “Management Holders”), (ii) HPS Investment Partners, LLC, Mezzanine Partners II Delaware Subsidiary, LLC, Offshore Mezzanine Partners Master Fund II, L.P., Institutional Mezzanine Partners II Subsidiary, L.P., AP Mezzanine Partners II, L.P., The Northwestern Mutual Life Insurance Company, The Northwestern Mutual Life Insurance Company for its Group Annuity Separate Account, Northwestern Mutual Capital Strategic Equity Fund III, LP, KCK-AMIH, Ltd. and United Insurance Company of America, Jade Real Assets Fund, L.P. (collectively, the “HPS Alta Mesa Holders”) and (iii) Bayou City Energy Management, LLC, BCE-MESA Holdings, LLC, and BCE-AMH Holdings, LLC (collectively, the “Bayou City Holders”). Mr. Ellis (who is our Chief Operating Officer-Upstream), through his ownership in AM MME Holdings, LP, Galveston Bay Resources Holdings, LP, Petro Acquisitions Holdings, LP, Petro Operating Company Holdings, Inc. and AM Equity Holdings, LP, will effectively control the vote of the Management Holders, and as a result, may be deemed to beneficially own the limited partnership interests in Alta Mesa beneficially owned by each such entity. William W. McMullen, through his ownership of the Bayou City Holders may be deemed to beneficially own the shares beneficially owned by the Bayou City Holders. Mr. Ellis, Mr. McMullen, the Management Holders, the HPS Alta Mesa Holders and the Bayou City Holders disclaim beneficial ownership of the shares of the Alta Mesa Contributor and the other Alta Mesa Contributor holders except to the extent of their respective pecuniary interests therein.
(6)
HPS Investment Partners, LLC manages each of Mezzanine Partners II Delaware Subsidiary, LLC, KFM Offshore, LLC, KFM Institutional, LLC, AP Mezzanine Partners II, L.P. and Jade Real Assets Fund, L.P., which collectively directly own approximately 8.45% of the limited partner interests in SRII Opco LP. The business address of each of these entities is c/o HPS Investment Partners, LLC, 40 West 57th street 33rd Floor, New York, NY 10019.
(7)
David M. Leuschen and Pierre F. Lapeyre, Jr. are the managers of Riverstone Management Group, L.L.C. (“Riverstone Management”), which is the general partner of Riverstone/Gower Mgmt Co Holdings, L.P. (“Riverstone/Gower”), which is the sole member of Riverstone Holdings LLC (“Holdings”), which is the sole shareholder of Riverstone Energy GP VI Corp, which is the managing member of Riverstone Energy GP VI, LLC (“Riverstone Energy GP’”) which is the general partner of Riverstone Energy Partners VI, L.P., which is the general partner of AMR Partners, the manager of AMR Partners-U and the managing member of Riverstone Energy VI Holdings GP, LLC, which is the general partner of the Riverstone Contributor. Riverstone Energy GP is managed by a managing committee consisting of Pierre F. Lapeyre, Jr., David M. Leuschen, E. Bartow Jones, N. John Lancaster, Baran Tekkora and Robert M. Tichio. As such, each of Riverstone Energy GP, Riverstone Energy GP VI Corp, Holdings, Riverstone/Gower, Riverstone Management, Mr. Leuschen and Mr. Lapeyre may be deemed to have or share beneficial ownership of the securities held directly by the Riverstone Contributor. Each such entity or person disclaims any such beneficial ownership. The business address of each of these entities and individuals is c/o Riverstone Holdings LLC, 712 Fifth Avenue, 36th Floor, New York, NY 10019.
Securities Authorized for Issuance under Equity Compensation Plans
We do not have any equity compensation plans.
Item 13.
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.
Management Services Agreement-High Mesa
In connection with the Closing, we entered into a management services agreement (the “High Mesa MSA”) with High Mesa. Under the High Mesa MSA, during the 180-day period following the Closing (the “Initial Term”), we will provide certain administrative, management and operational services necessary to manage the business of High Mesa and its subsidiaries (the “Services”), in each case, subject to and in accordance with an approved budget. Thereafter, the High Mesa MSA shall automatically renew for additional consecutive 180-day periods (each a “Renewal Term”), unless terminated by either party upon at least 90-days written notice to the other party prior to the end of the Initial Term or any Renewal Term. For a period of 60 days following the expiration of the term, we are obligated to assist High Mesa with the transition of the Services from us to a successor service provider. As compensation for the Services, including during any transition to a successor service provider, High Mesa will pay us each month (i) a management fee of $10,000, (ii) an amount equal to our costs and expenses incurred in connection with providing the Services as provided for in the approved budget and (iii) an amount equal to our costs and expenses incurred in connection with any emergency.
We are obligated to provide the Services in accordance with reasonable and prudent practices, as relevant to the Services, of the oil and gas industry, and in material compliance with all applicable laws; provided that we will only be liable under the High Mesa MSA for our own gross negligence, willful misconduct and/or fraud. We are only obligated to provide the Services under the High Mesa MSA to the extent that High Mesa has provided the funds necessary to undertake such Services.
Under the High Mesa MSA, High Mesa will have customary audit rights that will survive the termination or expiration of the High Mesa MSA. Each of High Mesa and us will have rights to terminate the High Mesa MSA prior to the expiration of the term (i) in the event of a sale or change of control of the other party, (ii) following an event related to bankruptcy of either party or (iii) following the other party’s material breach. In addition, High Mesa will have the right to terminate the High Mesa MSA prior to the expiration of the term upon a sale or change of control of High Mesa.
Management Services Agreement-Kingfisher
In connection with the Closing, we entered into a management services agreement (the “Kingfisher Agreement”) with Kingfisher. Under the Kingfisher Agreement, we will provide certain administrative, management and operational services necessary to manage the business of Kingfisher and its subsidiaries (the “Services”). As compensation for the Services, Kingfisher will pay us each month (i) a management fee of $10,000 and (ii) an amount equal to our costs and expenses incurred in connection with providing the Services.
We are obligated to provide the Services in accordance with reasonable and prudent practices, as relevant to the Services, of the oil and gas industry, and in material compliance with all applicable laws; provided that we will only be liable under the Kingfisher
Agreement for our own gross negligence, willful misconduct and/or fraud. Under the Kingfisher Agreement, Kingfisher will have customary audit rights that will survive the termination or expiration of the Kingfisher Agreement. See Note 19 - Subsequent Events for further details on the management services agreement
Pre-Closing Assignment Agreement
Prior to the Closing, we entered into the Assignment Agreement to transfer to the Alta Mesa Contributor our remaining non-STACK assets pursuant to the terms of the Alta Mesa Contribution Agreement, and the subsidiaries of the Alta Mesa Contributor agreed to indemnify us for any losses relating to employment, environmental and tax liabilities of such non-STACK assets.
Voting Agreement
Certain existing owners of the Company, including Mr. Chappelle, Mr. Ellis and certain affiliates of Bayou City and Highbridge, own an aggregate 10% voting interest in AMH GP and will continue to own such interest following the Closing. These existing owners were a party to a voting agreement with the AM Contributor and AMH GP, pursuant to which they have agreed to vote their interests in AMH GP as directed by the AM Contributor. In connection with the Closing, the parties amended and restated the voting agreement to include SRII Opco LP as a party and the existing owners agreed to vote their interests in AMH GP as directed by SRII Opco LP and appoint SRII Opco LP as their respective proxy and attorney-in-fact with respect to any voting matters related to their respective interests in AMH GP. The voting agreement will continue in force until SRII Opco LP elects to terminate the agreement or, with respect to each existing owner individually, such existing owner no longer owns a voting interest in AMH GP.
Ownership in Us and Our General Partner
Riverstone was admitted as a limited partner in connection with its $200 million capital contribution to us on August 17, 2017, in exchange for limited partner interests in us with respect to the economic rights to the STACK assets.
During 2016, our former Class B limited partner, High Mesa Inc. contributed $300 million to us. 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 in 2017.
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. The aggregate amount payable under the founder notes was $28.2 million and $27.0 million at December 31, 2017 and December 31, 2016, respectively. During the years ended December 31, 2017, 2016, and 2015, 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, 2017, 2016 and 2015. Such amounts have been added to the balance of the founder notes.
Subsequent to the year ended December 31, 2017, the founder notes were converted into equity interests in AM Contributor immediately prior to the closing of the business combination with AMR. See Note 11 - Long-term debt, net to the consolidated financial statements for further information.
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, 2017, 2016, and 2015, were approximately $186,000, $146,000, and $133,000. 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 $250,000, $425,000, and $275,000, for the years ended December 31, 2017, 2016, and 2015. 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 $150,000, $180,000, and $146,000 for the years ended December 31, 2017, 2016, and 2015. Additionally, his position provides him with the use of a company vehicle, similar to our other landman whose duties include field oversight.
Promissory Note Receivable - Northwest Gas Processing, LLC
We entered into a promissory note receivable with our affiliate, Northwest Gas Processing, LLC (“NWGP”), effective September 29, 2017, for approximately $1.5 million. The promissory note receivable was issued by NWGP to us and bears interest (or paid-in-kind interest from time to time) on the principal balance at a rate of 8% per annum, with interest payable in quarterly installments beginning January 1, 2018, and matures on February 28, 2019. Interest income on the promissory note receivable from our affiliate amounted to $32,000 during the year ended December 31, 2017. Such amounts have been added to the balance of the note receivable. The promissory note receivable is recorded in notes receivable due from affiliate under other assets on the consolidated balance sheets. The Company believes the promissory note to be fully collectible and accordingly has not recorded a reserve. During the fourth quarter of 2017, the $1.5 million promissory note was transferred from NWGP to HMS.
Note Receivable - High Mesa Services, LLC
We have a note receivable due from High Mesa Services, LLC (“HMS”), a subsidiary of High Mesa. The $8.5 million long-term 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. As of December 31, 2017 and 2016, the balance of the note receivable amounted to $10.8 million and $10.0 million, respectively. The Company believes the promissory note to be fully collectible and accordingly has not recorded a reserve. Interest income on the note receivable from our affiliate amounted to $0.8 million, $0.8 million and $0.7 million during the years ended December 31, 2017, 2016 and 2015, respectively. Such amounts have been added to the balance of the note receivable. On January 2, 2015, the receivable of $25.5 million related to the sale of our interest in a partially constructed midstream asset to our affiliate was collected. On December 31, 2015, we repurchased land originally sold to Northwest Gas Processing, LLC, a Delaware limited liability company (“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. During the year ended December 31, 2017 NWGP was billed for management services provided in the amount of approximately $0.1 million. High Mesa owns a controlling interest in NWGP.
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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. 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 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, 2017, we recorded $23.3 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.
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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 Kingfisher, which was subsequently amended on February 3, 2017, effective as of December 1, 2016. Prior to the business combination, High Mesa owns a minority interest in KFM. Alta Mesa also indirectly owns a minimal interest in Kingfisher through its less than 10% ownership of AEM. In connection with the business combination, Kingfisher is now a wholly owned subsidiary of SRII Opco LP. We have committed the oil and natural gas production from our Kingfisher County acreage, not otherwise committed to others, to Kingfisher.
Under the Crude Oil Gathering Agreement and the Gas Gathering and Processing Agreement, Oklahoma Energy dedicates and delivers to Kingfisher 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 Kingfisher’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, Kingfisher operates a crude oil gathering system for the purpose of providing gathering services to Oklahoma Energy. Kingfisher 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 Kingfisher 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, Kingfisher operates a gas gathering and processing system for the purpose of providing gathering and processing services to Oklahoma Energy. Kingfisher 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 Kingfisher 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 Kingfisher plant.
The aggregate amounts paid under the Crude Oil Gathering Agreement and Gas Gathering and Processing Agreement depends on the volumes produced and gathered pursuant to these agreements. Under such agreements, the fees for the years ended December 31, 2017 and 2016 were $24.4 million and $7.5 million, respectively. The plant commenced operations in the second quarter of 2016. These fees are recorded as marketing and transportation expense in the consolidated statements of operations. As of December 31, 2017 and 2016, we accrued approximately $2.0 million and $3.0 million as a reduction of accounts receivable on the consolidated balance sheets for fees related to marketing and transportation for the Kingfisher plant. Oklahoma Energy entered into an agreement with Kingfisher whereby the Company made a deposit of $10.0 million on January 13, 2017 to Kingfisher to provide us with 100,000 Dth/day for firm transportation. The deposit will be released back to us as we utilize the marketing and transportation services in 2018.
On September 21, 2016, we entered into an agreement with Kingfisher that beginning January 1, 2017 through January 31, 2022, we shall reimburse Kingfisher for 50% of any shortfall fee paid by Kingfisher to a third-party operator for any year in which the daily delivered gas volume is less than the daily gas volume committed. As of December 31, 2017, we have accrued approximately $1.0 million payable to Kingfisher for the shortfall fee during 2017. The amount is recorded in accounts payable from related party on the consolidated balance sheets.
Director Independence
Following the business combination, our Board of Directors consists of three members. 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 not made any determination as to whether the 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.
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, 2017, 2016 and 2015. Aggregate fees for professional services rendered to us by BDO for the years ended December 31, 2017 and 2016 were as follows:
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Audit Fees
The audit fees for the years ended December 31, 2017 and 2016, 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 and regulatory filings in connection with the business combination.
Audit-Related Fees
Audit-related fees for the year 2016 consist of 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 2017 and 2016 were approved by the Board of Directors.
PART IV
Item 15.
Item 15. Exhibits and Financial Statement Schedules
(a)Documents filed as part of this report:
1.Financial Statements:
(i)Report of Independent Registered Public Accounting Firm
(ii)Consolidated Balance Sheets as of December 31, 2017 and 2016
(iii)Consolidated Statements of Operations for each of the years in the three-year period ended December 31, 2017
(iv)Consolidated Statements of Changes in Partners’ Capital for each of the years in the three-year period ended December 31, 2017
(v)Consolidated Statements of Cash Flows for each of the years in the three-year period ended December 31, 2017
(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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* filed herewith.
Item 16. Form 10-K Summary
None.
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)
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By
/S/ MICHAEL A. MCCABE
Michael A. McCabe
Chief Financial Officer
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Dated March 29, 2018
In accordance with the Exchange Act, this report has been signed below on the 29th day of March, 2018, by the following persons on behalf of the registrant and in the capacities indicated.
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Signature
Title
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By:
/s/ HARLAN H. CHAPPELLE
Harlan H. Chappelle
President, Chief Executive Officer and Director (Principal Executive Officer)
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By:
/s/ JAMES T. HACKETT
James T. Hackett
Chairman of the Board, Director
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By:
/s/ MICHAEL E. ELLIS
Michael E. Ellis
Founder, Vice President of Engineering and Chief Operating Officer, Director
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By:
/s/ MICHAEL A. MCCABE
Michael A. McCabe
						
Vice President, Chief Financial Officer (Principal Financial Officer)
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By:
/s/ RONALD J. SMITH
Ronald J. Smith
						
Vice President, Chief Accounting Officer (Principal Accounting Officer)
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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.
“Basin”. A large natural depression on the earth’s surface in which sediments generally brought by water accumulate.
“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.
“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.
“BOE/d.” One BOE per day
“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.
“Condensate.” A mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.
“Cryogenic.” The process of using extreme cold to separate NGLs from natural gas. “DD&A”. Depreciation, depletion and amortization.
“DD&A.” Depreciation, depletion and amortization.
“Delineation.” The process of placing a number of wells in various parts of a reservoir to determine its boundaries and production characteristics.
“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 costs.” Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and natural gas. For a complete definition of development costs, refer to the SEC’s Regulation S-X, Rule 4-10(a)(7).
“Development project.” A development project is the means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project.
“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.
“Differential.” An adjustment to the price of oil, natural gas or natural gas liquids from an established spot market price to reflect differences in the quality and/or location of oil or natural gas.
“Downspacing.” Additional wells drilled between known producing wells to better exploit the reservoir. “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”. 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.
“Dth.” 1,000,000 Btu.
“Dth/d.” 1,000,000 Btu per day.
“DUC wells.” Drilled uncompleted wells.
“Economically producible.” The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation.
“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.
“EUR” or “Estimated ultimate recovery.” The sum of reserves remaining as of a given date and cumulative production as of that date.
“Exploitation.” A development or other project which may target proven or unproven reserves (such as probable or possible reserves), but which generally has a lower risk than that associated with exploration projects. “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.
“Exploratory well.” An exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or natural gas or in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well or a stratigraphic test well as those items are defined by the SEC.
“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.
“Gross acres or gross wells”. The total acres or wells, as the case may be, in which a working interest is owned.
“Held by production.” Acreage covered by a mineral lease that perpetuates a company’s right to operate a property as long as the property produces a minimum paying quantity of oil or natural gas.
“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.
“Hybrid.” A combination of Swell Packers and packer systems and sleeve systems.
“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.
“MBOE.” One thousand BOE.
“MBOE/d.” One thousand BOE per day. “Mcf”. One thousand cubic feet of natural gas.
“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.
“MMBOE.” One million BOE.
“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.
“Net Acres”. The percentage of total acres an owner has out of a particular number of acres, or a specified tract. An owner who has 50% interest in 100 acres owns 50 net acres.
“Net production.” Production that is owned by us less royalties and production due others.
“Net revenue interest.” A working interest owner’s gross working interest in production less the royalty, overriding royalty, production payment and net profits interest.
“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.
“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.
“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.
“Perf.” To create holes in the casing to achieve communication between the wellbore and the reservoir. “Play.” A geographic area with hydrocarbon potential. “Plug.” A downhole tool that is set inside the casing to isolate the lower part of the wellbore. “Pooling.” The bringing together of small tracts or fractional mineral interests in one or more tracts to form a drilling and production unit for a well under applicable spacing rules.
“Production costs.” Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities. For a complete definition of production costs, refer to the SEC’s Regulation S-X, Rule 4-10(a)(20).
“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.
“Proration unit.” A unit that can be effectively and efficiently drained by one well, as allocated by a governmental agency having regulatory jurisdiction.
“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.
“Proved developed reserves.” Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods and can be expected to be recovered through extraction technology installed and operational at the time of the reserve estimate.
“Proved properties.” Properties with proved 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 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.
“Realized price.” The cash market price less all expected quality, transportation and demand adjustments.
“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.
“Reserves.” Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.
“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.
“Resources.” Quantities of oil and natural gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable and another portion may be considered unrecoverable. Resources include both discovered and undiscovered accumulations.
“Royalty.” An interest in an oil and natural gas lease that gives the owner the right to receive a portion of the production from the leased acreage (or of the proceeds from the sale thereof), but does not require the owner to pay any portion of the production or development costs on the leased acreage. Royalties may be either landowner’s royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner. “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.
“Service well.” A well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells include gas injection, water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection for in-situ combustion.
“Slickwater.” A common fluid in the hydraulic fracturing process made up of brackish or saline water plus a chemical additive to reduce friction to allow for high pump rates.
“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.
“Spot market price.” The cash market price without reduction for expected quality, transportation and demand adjustments.
“STACK.” An oilfield in the eastern portion of the Anadarko Basin; 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
“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.
“Stratigraphic test well.” A drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. The classification also includes tests identified as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic tests are classified as “exploratory type” if not drilled in a known area or “development type” if drilled in a known area.
“Success rate.” The percentage of wells drilled which produce hydrocarbons in commercial quantities.
“Swell Packer.” A device run as part of the casing of the casing string that relies on elastomers to expand in the presence of formation fluids and isolate the formation at various intervals along the well path. “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.
“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.
“Unproved properties.” Properties with no 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.
“Workover.” Operations on a producing well to restore or increase production.
The terms “condensate,” “development costs,” “development project,” “development well,” “economically producible,” “estimated ultimate recovery (EUR),” “exploratory well,” “production costs,” “proved properties,” “reserves,” “reservoir,” “resources,” “service wells,” “stratigraphic test well” and “unproved properties” are defined by the SEC. Except as noted, the terms defined in this section are not the same as SEC definitions.
			 		
Below is an index to the financial statements and notes contained in Financial Statements and Supplementary Data.
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Partners and Board of Directors
Alta Mesa Holdings, LP
Houston, Texas
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Opinion on the Consolidated Financial Statements
We have audited the accompanying consolidated balance sheets of Alta Mesa Holdings, LP and subsidiaries (collectively, the “Company”) as of December 31, 2017 and 2016, the related consolidated statements of operations, changes in partners’ capital, and cash flows for each of the three years in the period ended December 31, 2017, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company and subsidiaries at December 31, 2017 and 2016, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2017, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.
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/s/ BDO USA, LLP
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We have served as the Company's auditor since 2014.
Houston, Texas
March 29, 2018
			
		
			
		
ALTA MESA HOLDINGS, LP AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
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The accompanying notes are an integral part of these consolidated financial statements.
			
		
			
		
ALTA MESA HOLDINGS, LP AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
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The accompanying notes are an integral part of these consolidated financial statements.
			
		
			
		
ALTA MESA HOLDINGS, LP AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS’ CAPITAL (DEFICIT)
YEARS ENDED DECEMBER 31, 2017, 2016 AND 2015
(in thousands)
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The accompanying notes are an integral part of these consolidated financial statements.
			
		
			
		
ALTA MESA HOLDINGS, LP AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
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The accompanying notes are an integral part of these consolidated financial statements.
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ALTA MESA HOLDINGS, LP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2017, 2016 AND 2015
NOTE 1 - NATURE OF OPERATIONS
Nature of Operations. Alta Mesa Holdings, LP (“Alta Mesa,” the “Company,” “us,” “our,” or “we”) is an independent exploration and production company engaged primarily in the acquisition, exploration, development, and production of oil and natural gas properties. Our principal area of operation is in the eastern portion of the Anadarko Basin referred to as the STACK. 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. Our operations in 2017 also included other oil and natural gas interests in Texas, Louisiana and Florida. In connection with the closing of the business combination, as discussed in Note 19, we distributed the remainder of our non-STACK assets to High Mesa Holdings, LP (“AM Contributor”) and completed our transition from a diversified asset base composed of a portfolio of conventional assets to an oil and liquids-rich resource unconventional play in the STACK. See Note 19 for further information on our business combination with Alta Mesa Resources, Inc. (formerly Silver Run Acquisition Corporation II (“AMR”)) and the distribution of non-STACK assets.
NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
We use accounting policies which reflect industry practices and conform to accounting principles generally accepted in the United States of America (“GAAP”). Certain prior-period amounts in the consolidated financial statements have been reclassified to conform to the current-year presentation. The reclassifications had no impact on net income (loss) or partners’ capital. During the fourth quarter of 2017, we sold our oil and natural gas properties located in the Weeks Island field in Louisiana. The sale of the Weeks Island field was a disposal completed in 2017 as part of the Company’s overall strategic shift to operate only in the STACK, which we completed upon the closing of the business combination as discussed in Note 19. As a result, we presented the assets and liabilities and operating results directly related to the sale of the Weeks Island field as discontinued operations within the consolidated statement of operations. We will reflect the remainder of the disposal of the non-STACK assets as discontinued operations in 2018. See Note 6 - Discontinued Operations for further discussion.
Principles of Consolidation. The consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries, after eliminating all significant intercompany transactions. The Company’s interests in oil and natural gas exploration and production ventures and partnerships are proportionately consolidated.
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.
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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 acquired 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.
Cash and Cash Equivalents. We consider all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents. The Company maintains cash balances at financial institutions in the United States of America, which at times exceed federally insured amounts. The Federal Deposit Insurance Corporation provides insurance up to $250,000 per depositor. We monitor the financial condition of the financial institutions and have experienced no losses associated with these accounts.
Restricted Cash. The Company classifies cash balances as restricted cash when cash is restricted as to withdrawal or usage. As of December 31, 2017 and 2016, the restricted cash represents cash received by the Company from production sold where the final division of ownership of the production is in dispute or there is unclaimed property for pooling orders in Oklahoma.
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In November 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“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. We adopted ASU 2016-18 in the fourth quarter of 2017.
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The following table provides a reconciliation of cash, cash equivalents and restricted cash reported within the consolidated balance sheets and the consolidated statements of cash flows:
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Accounts Receivable. Our receivables arise primarily from the sale of oil, natural gas and natural gas liquids and joint interest owner receivables for properties in which we serve as the operator. This concentration of customers may impact our overall credit risk, either positively or negatively, in that these entities may be similarly affected by changes in economic or other conditions affecting the oil and natural gas industry. Accounts receivable are generally not collateralized. We may have the ability to withhold future revenue disbursements to recover non-payment of joint interest billings on properties of which we are the operator. Accounts receivable from joint interest owners are stated at amounts due, net of an allowance for doubtful accounts.
Accounts receivable consisted of the following:
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Pooling interest relates to Oklahoma’s forced pooling process which requires the company to offer mineral interest owners the option to participate in the drilling of proposed wells. The pooling interest listed above represent costs of unbilled interests on wells which the company incurred before the pooling process was completed. Depending upon the outcome of the pooling process, these costs may be billed to potential working interest owners or added to oil and gas properties.
See Note 14 for further information regarding marketing arrangements with our primary marketing representative, ARM Energy Management, LLC (“AEM”) and significant concentrations. Accounts receivable from AEM arising from sales marketed on our behalf were $22.4 million and $14.9 million as of December 31, 2017 and 2016, respectively.
Allowance for Doubtful Accounts. We routinely assess the recoverability of all material trade and other receivables to determine their collectability. We accrue a reserve when, based on the judgment of management, it is probable that a receivable will not be collected and the amount of the reserve can be reasonably estimated.
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 statements of operations. Deferred financing costs related to the Company’s senior secured revolving credit facility are included in deferred financing costs, net and the deferred financing costs related to the senior unsecured notes are included in long-term debt, net, on the Company’s consolidated balance sheets.
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, delay rentals, gain or loss on settlement of asset retirement obligations and lease rentals. The costs of drilling exploratory wells and exploratory-type stratigraphic wells are initially capitalized, or “suspended” on the balance sheet pending determination of whether the well has discovered proved commercial reserves. See Note 5 for further details. 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. Assessments of such capitalized costs are made quarterly.
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 quarterly for impairment following the guidance provided in Account Standards Codification (ASC) 360-10-35, “Property, Plant and Equipment, Subsequent Measurement,” or 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.
Our evaluation of the Company’s proved properties resulted in impairment expense of $11.3 million, $16.1 million and $45.6 million for the years ended December 31, 2017, 2016 and 2015, respectively, primarily due to increased operating costs for impairments incurred during 2017 and lower forecasted commodity prices for impairments incurred during 2016 and 2015.
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 properties may be assessed in the aggregate. If unproved properties are found to be impaired, an impairment allowance is provided and a loss is recognized in the consolidated statements of operations. For the years ended December 31, 2017, 2016 and 2015, impairment expense of unproved properties was $19.0 million, $0.2 million, and $4.8 million, respectively.
Management evaluates whether the carrying value of all other long-lived assets has been impaired when circumstances indicate the carrying value of those assets may not be recoverable. This evaluation is based on undiscounted cash flow projections. The carrying amount is not recoverable if it exceeds the undiscounted sum of cash flows expected to result from the use and eventual disposition of the assets. Management considers various factors when determining if these assets should be evaluated for impairment.
If the carrying value is not recoverable on an undiscounted basis, the impairment loss is measured as the excess of the asset’s carrying value over its fair value. Management assesses the fair value of long-lived assets using commonly accepted techniques, and may use more than one method, including, but not limited to, recent third party comparable sales, internally developed discounted cash flow analysis and analysis from outside advisors. Significant changes in market conditions resulting from events such as the condition of an asset or a change in management’s intent to utilize the asset would generally require management to reassess the cash flows related to the long-lived assets. For the years ended December 31, 2017, 2016 and 2015, respectively, the Company did not record any impairment expense related to other long-lived assets.
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.
DD&A expense for the years ended December 31, 2017, 2016 and 2015 related to oil and natural gas properties was $92.1 million, $62.1 million, and $75.0 million, respectively.
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Leasehold improvements to offices are depreciated using the straight-line method over the life of the lease. Other property and equipment is depreciated using the straight-line method over periods ranging from three to seven years. Depreciation expense for non-oil and gas property and equipment for the years ended December 31, 2017, 2016 and 2015 was $2.4 million, $2.9 million, and $3.0 million respectively.
Investments. The Company’s investment consisted 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, 2017, and 2016. Under this method, the Company’s share of earnings or losses of the investment are not included in the consolidated statements of operations. As discussed in Note 19, on February 8, 2018, in connection with the closing of the business combination, we transferred our 10.17% ownership interest in Orion to AM Contributor.
At December 31, 2017, Alta Mesa was 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. For additional information on AEM, see Note 14.
Asset Retirement Obligations. We recognize liabilities for the future costs of dismantlement and abandonment of our wells, facilities, and other tangible long-lived assets along with an associated increase in the carrying amount of the related long-lived asset. The fair values of new asset retirement obligations are estimated using expected future costs discounted to present value. The cost of the tangible asset, including the asset retirement cost, is depleted over the useful life of the asset. Accretion expense is recognized as the discounted liability is accreted to its expected settlement value. Asset retirement obligations are subject to revision primarily for changes to the estimated timing and cost of abandonment.
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 7 for information on fair value).
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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 gain (loss) on derivative contracts in the consolidated statement of operations. Gains or losses from the settlement of matured derivatives contracts are also included in gain (loss) on derivatives contracts in the consolidated statement of operations. Cash flows from settlements of derivative contracts are classified as operating cash flows.
Income Taxes. The Company has elected under the Internal Revenue Code of 1986, as amended, 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 income taxes is included in the consolidated financial statements.
Net income (loss) for financial statement purposes may differ significantly from taxable income (loss) reportable to limited partners as a result of differences between the tax bases and financial reporting bases of assets and liabilities and the taxable income allocation requirements under the partnership agreement. As a result, the aggregate difference in the basis of net assets for financial and tax reporting purposes cannot be readily determined as the Partnership does not have access to information about each unitholder’s tax attributes in the Partnership. However, with respect to the Partnership, the Partnership’s book basis in its net assets exceeds the Partnership’s net tax basis by $340.1 million at December 31, 2017.
The Company is subject to the Texas margin tax, which is considered a state income tax, and is included in “Provision for (benefit from) state income tax” on the consolidated statements of operations. The Company records state income tax (current and deferred) based on taxable income, as defined under the rules for the margin tax.
We follow guidance issued by the FASB in accounting for uncertainty in income taxes. This guidance clarifies the accounting for income taxes by prescribing the minimum recognition threshold an income tax position is required to meet before being recognized in the consolidated financial statements and applies to all income tax positions. Each income tax position is assessed using a two-step process. A determination is first made as to whether it is more likely than not that the income tax position will be sustained, based upon technical merits, upon examination by the taxing authorities. If the income tax position is expected to meet the more likely than not criteria, the benefit recorded in the consolidated financial statements equals the largest amount that is greater than 50% likely to be realized upon its ultimate settlement.
			
		
			
		
We have considered our exposure under the standard at both the federal and state tax levels. We have not recorded any liabilities for uncertain tax positions as of December 31, 2017 and 2016. We record income tax, related interest, and penalties, if any, as a component of income tax expense. We did not incur any interest or penalties on income taxes for the years ended December 31, 2017, 2016 or 2015.
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The Company’s tax returns for the years ended December 31, 2014 forward remain open for examination. None of the Company’s federal or state tax returns are currently under examination by the relevant authorities.
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.
Fair Value of Financial Instruments. The fair values of cash, accounts receivable and current liabilities approximate book value due to their short-term nature. The fair value estimate of long-term debt under our senior secured revolving credit facility is not considered to be materially different from carrying value due to market rates of interest. The fair value of the debt to our founder is not practicable to determine because the transactions cannot be assumed to have been consummated at arm’s length, the terms are not deemed to be market terms, there are no quoted values available for this instrument, and an independent valuation would not be practicable due to the lack of data regarding similar instruments, if any, and the associated potential costs. We have estimated the fair value of our $500 million senior notes at $551 million on December 31, 2017. Derivative financial instruments are carried at fair value. For further information on fair values of financial instruments see Note 7 - Fair Value Disclosures and Note 11 - Long-Term Debt, Net and Notes Payable to Founder.
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 values at the time of the acquisition.
Recent Accounting Pronouncements Issued
In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASU 2014-09”), which seeks to provide a single, comprehensive revenue recognition model for all contracts with customers concerning the recognition, measurement and disclosure of revenue from those contracts. The revenue standard contains principles that an entity will apply to determine the measurement of revenue and timing of when it is recognized. Subsequent to the issuance of ASU 2014-09, the FASB issued various clarifications and interpretive guidance to assist entities with implementation efforts, including guidance pertaining to the presentation of revenues on a gross basis (revenues presented separately from associated expenses) versus a net basis. ASU 2014-09 and related interpretive guidance will be effective for interim and annual periods beginning after December 15, 2017, except for emerging growth companies that do not elect to use the extended transition period for complying with any new or revised financial accounting standards pursuant to Section 7(a)(2)(b) of the Securities Act. The standard allows for either full retrospective adoption, meaning the standard is applied to all periods presented in the financial statements, or modified retrospective adoption, meaning the standard is applied only to the most current period presented. As an emerging growth company we have elected to use the extended transition period and as a result, we will be required to adopt the standard during the first quarter of 2019 using the modified retrospective method with a cumulative adjustment to retained earnings as necessary. We will remain an emerging growth company for up to five years, although we will lose that status sooner if we have more than $1.0 billion of revenues at the end of any fiscal year, have more than $700.0 million in market value of our common stock held by non-affiliates measured as of June 30, or issue more than $1.0 billion of non-convertible debt over a three-year period. AMR is also an emerging growth company. It is reasonably possible that AMR could cease to be an emerging growth company by December 31, 2018. We intend to apply push down accounting and reflect AMR’s basis and accounting policies in our financial statements from the date of the business combination. Therefore, we could be required to adopt the standard in the fourth quarter of 2018.
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We are in the process of assessing our contracts and evaluating the impact on the consolidated financial statements. We are continuing to evaluate the provisions of ASU 2014-09 as it relates to certain sales contracts, and in particular, as it relates to disclosure requirements. In addition, we are evaluating the impact, if any, on the presentation of our future revenues and expenses under the new gross-versus-net presentation guidance. We continue to evaluate the impact of these and other provisions of ASU 2014-09 on our accounting policies, changes to relevant business practices, internal controls, and consolidated financial statements.
In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842)(“ASU 2016-02”), 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: (i) a lease liability, which is a lessee's obligation to make lease payments arising from a lease, measured on a discounted basis; and (ii) a right-of-use asset, which is an asset that represents a 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. ASU 2016-02 also requires disclosures designed to provide information on the amount, timing, and uncertainty of cash flows arising from leases. In January 2018, the FASB issued ASU No. 2018-01, Land easement practical expedient for transition to Topic 842 (“ASU 2018-01”), which provides an optional transition practical expedient to not evaluate under Topic 842 existing or expired land easements that were not previously accounting for as leases under Topic 840, Leases. The standard will be effective for interim and annual periods beginning after December 15, 2018 for public companies and annual periods beginning after December 15, 2019 for all other entities, with earlier adoption permitted. In the normal course of business, we enter into operating lease agreements to support our exploration and development operations and lease assets such as drilling rigs, well equipment, compressors, office space and other assets.
At this time, we cannot reasonably estimate the financial impact ASU 2016-02 will have on our financial statements; however, the adoption and impletion of ASU 2016-02 is expected to have an impact on our consolidated balance sheets resulting in an increase in both the assets and liabilities relating to our operating lease activities greater than twelve months. The adoption is also expected to result in increase in depreciation, depletion and amortization expense, interest expense recorded on our consolidated statement of operations, and additional disclosures. As part of our assessment to date, we have formed an implementation work team and will complete our evaluation in 2018. As we continue to evaluate and implement the standard, we will provide additional information about the expected financial impact at a future date. As an emerging growth company we have elected to use the extended transition period and as a result, we will be required to adopt the standard in 2020. We could cease to be an emerging growth company if we meet the requirements as described above. AMR is also an emerging growth company. It is reasonably possible that AMR could cease to be an emerging growth company by December 31, 2018. We intend to apply push down accounting and reflect AMR’s basis and accounting policies in our financial statements from the date of the business combination. Therefore, we could be required to adopt the standard on January 1, 2019.
In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments (“ASU 2016-15”), 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 and interim periods within those fiscal years beginning after December 15, 2017 for public companies and for fiscal years beginning after December 15, 2018 for all other entities. As an emerging growth company we have elected to use the extended transition period and as a result, we will be required to adopt the standard in 2019. AMR is also an emerging growth company. It is reasonably possible that AMR could cease to be an emerging growth company by December 31, 2018. We intend to apply push down accounting and reflect AMR’s basis and accounting policies in our financial statements from the date of the business combination. Therefore, we could be required to adopt the standard in the fourth quarter of 2018. The adoption of this guidance will not impact our financial position or results of operations but could result in presentation changes on our consolidated statements of cash flows.
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In January 2017, the FASB issued ASU No. 2017-01, Clarifying the Definition of a Business (“ASU 2017-01”), 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 interim and annual periods after December 15, 2017 for public companies and annual periods beginning after December 15, 2018 for all other entities. The amendments should be applied prospectively on or after the effective date and disclosures are not required at transition. Early adoption is permitted for transactions for which the acquisition date occurs before the issuance date or effective date of the amendments, only when the transaction has not been reported in financial statements that have been issued or made available for issuance. The Company early adopted ASU 2017-01 in the fourth quarter of 2017. We do not expect the adoption of ASU 2017-01 to have a material impact on our consolidated financial statements; however these amendments could result in the recording of fewer business combinations in the future periods.
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NOTE 3 - SUPPLEMENTAL CASH FLOW INFORMATION
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Supplemental cash flow disclosures and non-cash investing and financing activities are presented below:
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NOTE 4 - SIGNIFICANT ACQUISITIONS AND DIVESTITURES
2017 Activity
In December 2017, we sold our assets located in the Weeks Island field to Texas Petroleum Investment. See Note 6-Discontinued Operations for further details.
In September 2017, we completed a transaction to acquire certain proved oil and natural gas properties from Brown & Borelli, et al (the “B&B Acquisition”) for a purchase price of approximately $8.2 million, net of customary post-closing purchase price adjustments. We funded the acquisition with cash on hand. The acquisition was accounted for using the acquisition method under ASC 805, “Business Combinations,” which requires acquired assets and liabilities to be recorded at fair value as of the acquisition date. The difference between the historical results and post-acquisition results of operations and the unaudited pro forma results of operations for the twelve months ended December 31, 2017 and 2016 was determined to be de minimus and therefore pro forma information has not been provided.
A summary of the consideration paid and the allocation of the total purchase price to the assets acquired and the liabilities assumed in the B&B Acquisition based on the preliminary fair value at the acquisition date, is as follows:
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The fair value of the net assets acquired was approximately $10.3 million. As the fair value of the net assets acquired exceeded the total consideration paid, we recorded a bargain purchase gain of approximately $1.7 million which primarily was a result of
			
		
			
		
timing from the execution of the purchase and sale agreement to the closing date of the acquisition at which time the value of the underlying properties increased substantially due to increases in the value of proved reserves. The bargain purchase gain is reflected in gain on acquisition of oil and natural gas properties on our consolidated statements of operations.
﻿In July 2017, we closed on our acquisition to acquire certain oil and natural gas properties in Oklahoma with an unaffiliated third party for a purchase price of approximately $45.6 million, net of customary post-closing adjustments. The acquired oil and natural gas properties were primarily unproved leasehold. We accounted for this transaction as an asset acquisition with substantially all of the purchase price allocated to unproved property within oil and natural gas properties, successful efforts method, net. We funded the acquisition with borrowings under our senior secured revolving credit facility.
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In April 2017, we completed an acquisition of certain non-STACK proved oil and natural gas properties from Setanta Energy, LLC (the “Setanta” Acquisition) for a purchase price of approximately $0.9 million, net of customary post-closing purchase price adjustments. We funded the acquisition with borrowings under our senior secured revolving credit facility. This purchase increases our working interest in various wells in which we already hold an interest. The acquisition was accounted for using the acquisition method under ASC 805. The difference between the historical results and post-acquisition results of operations and the unaudited pro forma results of operations for the twelve months ended December 31, 2017 and 2016 was determined to be de minimus and therefore pro forma information has not been provided.
A summary of the consideration paid and the allocation of the total purchase price to the assets acquired and the liabilities assumed in the Setanta Acquisition based on the preliminary fair value at the acquisition date, is as follows:
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The fair value of the net assets acquired was approximately $2.6 million. As the fair value of the net assets acquired exceeded the total consideration paid and liabilities assumed, we recorded a bargain purchase gain of approximately $1.6 million which primarily was a result of the seller’s financial distress and needing to dispose of the underlying properties for cash in an expedited manner which resulted in a below market purchase price. The bargain purchase gain is reflected in gain on acquisition of oil and natural gas properties on our consolidated statements of operations.
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2016 Activity
During 2016, we acquired approximately $10.6 million of oil and natural gas properties in Oklahoma which were primarily related to unevaluated leasehold.
On December 31, 2016, our Class B partner, High Mesa, Inc. (“High Mesa”) 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. The Company accounted for the Contributed Wells as a business combination and therefore, recorded the contribution at their estimated contribution date fair value. 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.
			
		
			
		
The unaudited pro forma combined financial results, had the contribution of the Contributed Wells occurred at January 1, 2016, are provided below. The Contributed Wells came online during 2016, therefore, no unaudited pro forma combined results are shown for the beginning of the comparable prior year.
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This unaudited pro forma information has been derived from historical information and is for illustrative purposes only. The unaudited pro forma financial information is not necessarily indicative of what actually would have occurred if the contribution had been completed as of the beginning of the period, nor are they necessarily indicative of future results.
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2015 Activity
Alta Mesa Eagle, LLC Divestiture
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On September 30, 2015, we closed the sale of all of the membership interests (the “Membership Interests”) in Alta Mesa Eagle, LLC (“AME”), our wholly owned subsidiary, to EnerVest Energy Institutional Fund XIV-A, L.P. and EnerVest Energy Institutional Fund XIV-WIC, L.P. (collectively, “EnerVest”) pursuant to a purchase and sale agreement entered into by us, AME and EnerVest on September 16, 2015 (the “Eagle Ford divestiture”). AME owned our remaining non-operated oil and natural gas producing properties located in the Eagle Ford shale play in Karnes County, Texas. In connection with the Eagle Ford divestiture, we disposed of all of our remaining interests in this area. The effective date of the transaction (the “Effective Date”) was July 1, 2015.
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The aggregate cash purchase price for the Membership Interests was $125.0 million subject to certain adjustments, consisting of $118.0 million (the “Base Purchase Price”), and additional contingent payments of approximately $7.0 million in the aggregate, payable to us by EnerVest by the 15th of each calendar month in which certain amounts owed to AME prior to the Effective Date have been received. The purchase and sale agreement provides for customary purchase price adjustments to the Base Purchase Price based on the Effective Date. As of December 31, 2015, we received net proceeds of $122.0 million including $4.0 million of customary purchase price adjustments, and recognized a gain of approximately $67.6 million. Cash received was utilized to pay down borrowings under our senior secured revolving credit facility. As of the Effective Date, the estimated net proved reserves sold were approximately 7.8 MMBOE.
The sale of AME contributed approximately $68.9 million in pre-tax profit for the year ended December 31, 2015, which includes the $67.6 million gain on sale of asset.
Kingfisher Leasehold Acquisition
On July 6, 2015, we acquired approximately 19,000 net acres of primarily undeveloped leasehold interest in Kingfisher County, Oklahoma. The consideration for the purchase was approximately $46.2 million and was subject to customary purchase price adjustments. The effective date of the acquisition was April 1, 2015. The purchase was funded with borrowings under our senior secured revolving credit facility.
NOTE 5 - PROPERTY AND EQUIPMENT
Property and equipment consists of the following:
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Capitalized Exploratory Well Costs
The following table reflects the net changes in capitalized exploratory well costs during 2017, 2016, and 2015. The table does not include amounts that were capitalized and subsequently charged to expense within the same year.
The ending balance in capitalized exploratory well costs includes the costs of four wells primarily in one prospect that were capitalized for periods greater than one year at December 31, 2017. We have capitalized approximately $0.1 million and $0.7 million of exploratory well costs covering periods greater than one year at December 31, 2017 and 2016. We continue to assess and evaluate these projects.
NOTE 6 - DISCONTINUED OPERATIONS
On December 28, 2017, we sold our assets located in the Weeks Island field, located in Iberia Parish, Louisiana, to Texas Petroleum Investment Company for proceeds of $22.5 million, subject to customary purchase price adjustments to settle in 2018. The sale of the Weeks Island field represented the initial step in our strategic shift in our operations as we transitioned from a company with a diversified asset base composed of a portfolio of conventional assets to an oil and liquids-rich resource unconventional play located in the STACK, Oklahoma, which we completed upon the closing of the business combination as discussed in Note 19. As a result of this strategic shift, we classified all the related assets and liabilities directly associated with discontinued operations in the consolidated balance sheets. The operating results and other items directly related to the sale of the Weeks Island field have been segregated and presented as discontinued operations for all periods presented in our consolidated statements of operations and the related notes except Note 21 - Supplemental Oil and Natural Gas Disclosures.
The assets and liabilities directly related to the Weeks Island field have been reclassified to assets and liabilities associated with discontinued operations as follows:
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The results of operations of the Weeks Island field and other items directly related to the sale have been reclassified in discontinued operations as follows:
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Reflects severance payments provided to employees who were displaced as a direct result of the sale of the Weeks Island field.
The total operating and investing cash flows of the Weeks Island field are as follows:
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In connection with the closing of the business combination as described in Note 19, we distributed our remaining non-STACK assets to the AM Contributor. The sale of the Weeks Island field in the fourth quarter of 2017 was part of an overall strategic plan to be in the STACK pure play. Therefore, the sale of the Weeks Island field is considered to be the first step in a strategic shift with significant impact that was completed in stages. The remaining non-STACK assets distributed subsequent to year end will be reflected as discontinued operations in future filings when the criteria for discontinued operations for the remaining non-STACK are met under ASC 205-20, “Discontinued Operations”.
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NOTE 7 - FAIR VALUE DISCLOSURES
The Company follows ASC 820, “Fair Value Measurements and Disclosure.” ASC 820 provides a hierarchy of fair value measurements, based on the inputs to the fair value estimation process. It requires disclosure of fair values classified according to defined “levels,” which are based on the reliability of the evidence used to determine fair value, with Level 1 being the most reliable and Level 3 the least. Level 1 evidence consists of observable inputs, such as quoted prices in an active market. Level 2 inputs typically correlate the fair value of the asset or liability to a similar, but not identical item which is actively traded. Level 3 inputs include at least some unobservable inputs, such as valuation models developed using the best information available in the circumstances.
We utilize the modified Black-Scholes and the Turnbull Wakeman option pricing models to estimate the fair values of oil and natural gas derivative contracts. Inputs to these models include observable inputs from the New York Mercantile Exchange (“NYMEX”) and other exchanges for futures contracts, and inputs derived from NYMEX observable inputs, such as implied volatility of oil and natural gas prices. We have classified the fair values of all our oil, natural gas, and natural gas liquids derivative contracts as Level 2.
Our senior notes are carried at historical cost. We estimate the fair value of the senior notes for disclosure purposes (see Note 2). This estimation is based on the most recent trading values of the notes at or near the reporting date, a Level 1 classification.
Oil and natural gas properties are subject to impairment testing and potential impairment write down as described in Note 2. Oil and natural gas properties with a carrying amount of $37.4 million were written down to their fair value of $7.1 million, resulting in an impairment charge of $30.3 million for the year ended December 31, 2017. Oil and natural gas properties with a carrying amount of $33.9 million were written down to their fair value of $17.6 million, resulting in an impairment charge of $16.3 million for the year ended December 31, 2016. Oil and natural gas properties with a carrying amount of $78.0 million were written down to their fair value of $27.6 million, resulting in an impairment charge of $50.4 million for the year ended December 31, 2015. The impairment analysis is based on the estimated discounted future cash flows for those properties. Significant Level 3 assumptions used in the calculation of estimated discounted cash flows included our estimate of future oil and natural gas prices, production costs, development expenditures, estimated quantities and timing of production of proved reserves, appropriate risk-adjusted discount rates, and other relevant data.
New additions to asset retirement obligations result from estimations for new properties, and fair values for them are categorized as Level 3. Such estimations are based on present value techniques which utilize company-specific information for such inputs as cost and timing of plug and abandonment of wells and facilities. We recorded a total of $1.8 million in additions to asset retirement obligations measured at fair value for the year ended December 31, 2017. We recorded a total of $1.4 million in additions to asset retirement obligations measured at fair value for the year ended December 31, 2016.
The following table presents information about our financial assets and liabilities measured at fair value on a recurring basis as of December 31, 2017 and 2016, and indicates the fair value hierarchy of the valuation techniques we utilized to determine such fair value:
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The amounts above are presented on a gross basis. Presentation on our consolidated balance sheets utilizes netting of assets and liabilities with the same counterparty where master netting agreements are in place.
NOTE 8 - DERIVATIVE FINANCIAL INSTRUMENTS
We account for our derivative contracts under the provisions of ASC 815, “Derivatives and Hedging.” We have entered into forward-swap contracts and collar contracts to reduce our exposure to price risk in the spot market for oil, natural gas, and natural gas liquids. From time to time we also utilize financial basis swap contracts, which address the price differential between the benchmark index price and the specific locational index pricing referenced in certain of our crude oil, natural gas, and natural gas liquids sales contracts. Substantially all of our hedging agreements are executed by affiliates of the lenders under our senior secured revolving credit facility described in Note 11 below, and are collateralized by the security interests of the respective affiliated lenders in certain of our assets under the senior secured revolving credit facility. The contracts settle monthly and are scheduled to coincide with oil production equivalent to barrels (Bbl) per month, natural gas production equivalent to volumes in millions of British thermal units (MMBtu) per month, and natural gas liquids production to volumes in gallons (Gal) per month. The contracts represent agreements between us and the counter-parties to exchange cash based on a designated price, or in the case of financial basis hedging contracts, based on a designated price differential between various benchmark prices. Cash settlement occurs monthly. No derivative contracts have been entered into for trading purposes.
From time to time, we enter into interest rate swap agreements with financial institutions to mitigate the risk of loss due to changes in interest rates.
We have not designated any of our derivative contracts as fair value or cash flow hedges. Accordingly, we use mark-to-market accounting, recognizing changes in the fair value of derivative contracts in the consolidated statements of operations at each reporting date.
Derivative contracts are subject to master netting arrangements and are presented on a net basis in the consolidated balance sheets. This netting can cause derivative assets to be ultimately presented in a (liability) account on the consolidated balance sheets. Likewise, derivative (liabilities) could be presented in an asset account.
The following table summarizes the fair value (see Note 7 for further discussion of fair value) and classification of our derivative instruments, none of which have been designated as hedging instruments under ASC 815:
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The following table summarizes the effect of our derivative instruments in the consolidated statements of operations:
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Other receivables include $1.4 million and $7.8 million of derivative positions settled, but not yet received as of December 31, 2017 and 2016, respectively.
Although our counterparties provide no collateral, the master derivative agreements with each counterparty effectively allow the Company, so long as it is not a defaulting party, after a default or the occurrence of a termination event, to set-off an unpaid hedging agreement receivable against the interest of the counterparty in any outstanding balance under the senior secured revolving credit facility. If a counterparty were to default in payment of an obligation under the master derivative agreements, we could be exposed to commodity price fluctuations, and the protection intended by the hedge could be lost. The value of our derivative financial instruments would be impacted.
			
		
			
		
We had the following open derivative contracts for crude oil at December 31, 2017:
OIL DERIVATIVE CONTRACTS
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We had the following open derivative contracts for natural gas at December 31, 2017:
NATURAL GAS DERIVATIVE CONTRACTS
In those instances where contracts are identical as to time period, volume, strike price, and counterparty, but opposite as to direction (long and short), the volumes and average prices have been netted in the two tables above. Prices stated in the table above for oil may settle against either NYMEX, Brent ICE, or Argus Louisiana Light Sweet Crude indices or quotations, or may reflect a mix of positions settling on various of these benchmarks.
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We had the following open financial basis swap contracts for natural gas at December 31, 2017:
BASIS SWAP DERIVATIVE CONTRACTS
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(1) Represents short swaps that fix the basis differentials between Tex/OKL Panhandle Eastern Pipeline (“PEPL”) Inside FERC (“IFERC”) and NYMEX Henry Hub and WAHA and NYMEX Henry Hub.
			
		
			
		
NOTE 9 - ASSET RETIREMENT OBLIGATIONS
A summary of the changes in our asset retirement obligations is included in the table below:
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The total revisions included $2.6 million and $1.3 million related to additions to property, plant and equipment for the year ended December 31, 2017 and 2016, respectively. We transferred approximately $18.9 million of asset retirement obligations liabilities as a result of the sale of the Weeks Island field during the fourth quarter 2017.
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NOTE 10 - RELATED PARTY TRANSACTIONS
We have notes payable to our founder which bear interest at 10% with a balance of $28.2 million and $27.0 million at December 31, 2017 and 2016, respectively. Subsequent to the year ended December 31, 2017, the founder notes were converted into equity interests in the AM Contributor immediately prior to the closing of the business combination with AMR. See Note 11 for further information.
Michael E. Ellis, our founder, Chief Operating Officer, and Chairman of the Board, received no capital distributions during the years ended December 31, 2017, 2016 and 2015.
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, 2017, 2016 and 2015 were approximately $186,000, $146,000 and $133,000. The contract may be terminated by either party without penalty upon 30 days’ notice. These amounts are recorded in general and administrative expenses (“G&A”) expense on the consolidated statements of operations.
David McClure, our Vice President of Facilities and Midstream, and the son-in-law of our CEO, Harlan H. Chappelle, received total compensation of $250,000, $425,000 and $275,000 for the years ended December 31, 2017, 2016 and 2015. Additionally, his position provides him with the use of a company vehicle, similar to our other engineers whose duties include field oversight. These amounts are recorded in G&A expense on the consolidated statements of operations.
David Pepper, one of our Landmen, and the cousin of our Vice President of Land and Business Development, David Murrell, received total compensation of $150,000, $180,000 and $146,000 for the years ended December 31, 2017, 2016 and 2015. Additionally, his position provides him with the use of a company vehicle, similar to our other engineers whose duties include field oversight. These amounts are recorded in G&A expense on the consolidated statements of operations.
On January 13, 2016, our wholly-owned subsidiary Oklahoma Energy Acquisitions, LP (“Oklahoma Energy”) entered into a joint development agreement (the “joint development agreement”), with BCE, a fund advised by Bayou City Energy Management LLC (“Bayou City”), to fund a portion of our drilling operations and to allow us to accelerate development of our STACK acreage. The drilling program initially called for the development of forty identified well locations, which developed in two tranches of twenty wells each. The parties subsequently agreed to add a third and fourth tranche of investment that will allow for the drilling of an additional forty wells. On December 31, 2016, High Mesa purchased from BCE and contributed interests in 24 producing wells drilled under the joint development agreement to us. See Notes 4 and 17 for further details. 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. As of December 31, 2017, 54 joint wells have been drilled or spudded leaving 26 wells to be drilled under the joint development agreement.
			
		
			
		
Under the joint development agreement, as amended on December 31, 2016, 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 the aggregate limit of $64 million in any tranche. In exchange for the payment of drilling and completion costs, BCE receives 80% of our working interest in each wellbore, which 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. The approximate dollar value of the amount involved in this transaction or Messrs. McMullen or Stoner’s interests in the transaction depends on a number of factors outside their control and is not known at this time. As of December 31, 2017 and 2016, we recorded $23.4 million and $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 the joint development agreement. Subsequent to year end, BCE advanced us approximately $39.5 million to drill additional wells under the joint development agreement.
During the year ended December 31, 2016, High Mesa contributed $311.3 million to us, of which $7.9 million is included in receivables due from affiliate at December 31, 2016 and the amount was collected in January 2017. During the year ended December 31, 2015, High Mesa contributed $20 million to us. For additional information, see Note 17 - Partners’ Capital. As of December 31, 2017 and 2016, approximately $0.8 million and $0.9 million, respectively, were due from High Mesa for reimbursement of expenses which is recorded in the receivables due from affiliates on the consolidated balance sheets.
We have a note receivable due from High Mesa Services, LLC (“HMS”), a subsidiary of High Mesa. The $8.5 million long-term 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. As of December 31, 2017 and 2016, the balance of the note receivable amounted to $10.8 million and $10.0 million, respectively. The Company believes the promissory note to be fully collectible and accordingly has not recorded a reserve. Interest income on the note receivable from our affiliate amounted to $0.9 million, $0.8 million and $0.7 million during the years ended December 31, 2017, 2016 and 2015, respectively. Such amounts have been added to the balance of the note receivable. On January 2, 2015, the receivable of $25.5 million related to the sale of our interest in a partially constructed midstream asset to our affiliate was collected. On December 31, 2015, we repurchased land originally sold to Northwest Gas Processing, LLC, a Delaware limited liability company (“NWGP”) at cost of $0.7 million.
We entered into a promissory note receivable with our affiliate, NWGP, effective September 29, 2017, for approximately $1.5 million. The promissory note receivable was issued by NWGP to us and bears interest (or paid-in-kind interest from time to time) on the principal balance at a rate of 8% per annum, with interest payable in quarterly installments beginning January 1, 2018, and matures on February 28, 2019. Interest income on the promissory note receivable from our affiliate amounted to $32,000 during the year ended December 31, 2017. Such amounts have been added to the balance of the note receivable. The promissory note receivable is recorded in notes receivable due from affiliate under other assets on the consolidated balance sheets. The Company believes the promissory note to be fully collectible and accordingly has not recorded a reserve. During the fourth quarter of 2017, the $1.6 million promissory note was transferred from NWGP to HMS.
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. NWGP was billed for management services provided in the amount of approximately $0.1 million during each of the years ended December 31, 2017 and 2016.
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 Kingfisher Midstream, LLC (“Kingfisher”), a Delaware limited liability company, which was subsequently amended and restated on February 3, 2017, effective as of December 1, 2016. High Mesa owns a minority interest in Kingfisher. Prior to Closing of the business combination, Alta Mesa also indirectly owned a minimal interest in Kingfisher 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 Kingfisher for gathering and processing.
Under the Crude Oil Gathering Agreement and the Gas Gathering and Processing Agreement, Oklahoma Energy dedicates and delivers to Kingfisher 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 Kingfisher’s system for gathering and processing. The Crude Oil Gathering Agreement and Gas Gathering and Processing Agreement 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, Kingfisher operates a crude oil gathering system for the purpose of providing gathering services to Oklahoma Energy. Kingfisher receives from Oklahoma Energy a fixed service fee per barrel of crude oil delivered. The
			
		
			
		
fixed gathering fee is subject to an annual percentage increase tied to the consumer price index. Oklahoma Energy also pays Kingfisher its allocated share, if any, of the electricity consumed in the operation of the crude oil gathering system.
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Under the Gas Gathering and Processing Agreement, Kingfisher operates a gas gathering and processing system for the purpose of providing gathering and processing services to Oklahoma Energy. Kingfisher 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 Kingfisher 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 Kingfisher plant.
The aggregate amounts paid under the Crude Oil Gathering Agreement and Gas Gathering and Processing Agreement depends on the volumes produced and gathered pursuant to these agreements. The plant commenced operations in the second quarter of 2016. Under such agreements, the fees for the years ended December 31, 2017 and 2016 were $24.4 million and $7.5 million, respectively. These fees are recorded as marketing and transportation expense in the consolidated statements of operations. As of December 31, 2017 and 2016, we accrued approximately $2.0 million and $3.0 million as a reduction of accounts receivable on the consolidated balance sheets for fees related to marketing and transportation for the Kingfisher plant. Oklahoma Energy entered into an agreement with Kingfisher whereby the Company made a deposit of $10.0 million on January 13, 2017 to Kingfisher to provide us with 100,000 Dth/day for firm transportation. As of December 31, 2017, we reflected approximately $1.0 million as prepaid and other assets and the remaining portion of the deposit is recorded on the consolidated balance sheets under deposits and other assets. The amount reflected as prepaid and current asset represents our estimated reduction of our deposit within the next twelve months. The deposit will be released back to us as we utilize the marketing and transportation services in 2018.
The Company and Kingfisher (the “Parties”) have agreed whereby we would reimburse Kingfisher and/or Kingfisher would reimburse us for certain right-of-way costs and construction costs related to the midstream infrastructure incurred by each party, which would otherwise be paid directly. The reimbursement resulted in a net payment of $1.5 million due to Kingfisher as of December 31, 2017. Additionally, the Company purchased approximately $6.1 million of right-of-way and construction costs related to the construction of a pipeline undertaken by Kingfisher to connect our production to the gathering point. These oil and gas properties costs of $7.6 million were offset by net production receivables of approximately $3.2 million owed to us by Kingfisher. As of December 31, 2017, the combination of these amounts of $5.5 million was recorded in accounts payable- related party on our consolidated balance sheet.
On September 21, 2016, we entered into an agreement with Kingfisher that beginning January 1, 2017 through January 31, 2022, we shall reimburse Kingfisher for 50% of any shortfall fee paid by Kingfisher to a third-party operator for any year in which the daily delivered gas volume is less than the daily gas volume committed. As of December 31, 2017, we have accrued approximately $1.0 million payable to Kingfisher for the shortfall fee during 2017. The amount is recorded in accounts payable -related party on the consolidated balance sheet.
In connection with the closing of the business combination, we entered into a management services agreement with High Mesa with respect to our non-STACK assets that were distributed to High Mesa’s subsidiary and we entered into a management services agreement with Kingfisher. See Note 19 - Subsequent Events for further details on the management services agreement.
NOTE 11 - LONG TERM DEBT, NET AND NOTES PAYABLE TO FOUNDER
Long-term debt, net consists of the following:
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Senior Secured Revolving Credit Facility. In November 2016, we entered into the Seventh Amended and Restated Credit Agreement (as amended, the “credit facility”) with Wells Fargo Bank, National Association, as administrative agent, and a syndicate of banks. On June 13, 2017, we entered into an Agreement and Amendment No. 2 (the “Second Amendment”) to the credit facility which, among other things: (i) increased our borrowing base from $287.5 million to $315.0 million until the next scheduled redetermination and (ii) permits us to make a one-time cash distribution of no more than $1.0 million to a limited partner. The amended and restated credit facility, among other things, (i) reaffirms the existing borrowing base amount of $315.0 million through the new redetermination of the borrowing base, (ii) increases the maximum credit amount from $500 million to $750 million, subject to borrowing base limit (iii) extends the maturity of the credit facility to November 10, 2020, (iv) increases our pricing grid by 25 to 50 basis points (depending on our leverage ratio), and (v) increases our mortgage requirement from 85% of the value of our proven reserves to 90%. As of December 31, 2017, our borrowing base was $315 million.
As of December 31, 2017, the Company had $117.1 million outstanding with $184.3 million of available borrowing capacity under the credit facility. The principal amount is payable at maturity. The credit facility borrowing base is redetermined semi-annually, on or about May 1 and November 1 of each year. The credit facility is secured by substantially all of our oil and natural gas properties and is based on our proved reserves and the value attributed to those reserves. We have a choice of borrowing in Eurodollars or at the “Reference Rate,” which is based on the prime rate of Wells Fargo Bank, National Association. The credit facility bears interest at the London Interbank Offered Rate (“LIBOR”) plus applicable margins ranging from 2.75% and 3.75% if our leverage ratio does not exceed 3.25 to 1.00, depending on the percentage of our borrowing based utilized, and ranging from 3.00% to 4.00% if our leverage ratio exceeds 3.25 to 1.00. The reference 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 a margin ranging from 1.75% to 2.75% if our leverage ratio does not exceed 3.25 to 1.00, depending on the percentage of our borrowing base utilized, and ranging from 2.00% to 3.00% if our leverage ratio exceeds 3.25 to 1.00. The weighted average and effective interest rate on outstanding borrowings was 5.48% as of December 31, 2017 and 4.00% as of December 31, 2016. The letters of credit outstanding as of December 31, 2017 and 2016 were $13.6 million and $7.6 million, respectively.
Subsequent to year end on February 9, 2018 (the “Closing Date”) and in connection with the closing of the Contribution Agreement (as described in Note 19 - Subsequent Events), we entered into the Eighth Amended and Restated Credit Agreement with Wells Fargo Bank, National Association, as the administrative agent (the “Eighth A&R credit facility”). The Eighth A&R credit facility is for an aggregate maximum credit amount of $1.0 billion with an initial $350.0 million borrowing base limit. The Eighth A&R credit facility does not permit us to borrow funds if at the time of such borrowing it is not in pro forma compliance with its financial covenants. As of February 9, 2018, all outstanding balances under our credit facility were paid in full. We have no borrowings under the Eighth A&R credit facility.
The principal amounts borrowed are payable on the maturity date on February 9, 2023. We have a choice of borrowing in Eurodollars or at the reference rate, with such borrowings bearing interest, payable quarterly for reference rate loans and one month, three month or six month periods for Eurodollar loans. Eurodollar loans bear interest at a rate per annum equal to the rate at the LIBOR, plus an applicable margin ranging from 2.00% to 3.00%. Reference 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 1.00% to 2.00%. The next scheduled redetermination of our borrowing base is on April 1, 2018. The borrowing base may be reduced in connection with the next redetermination of its borrowing base. The amounts outstanding under the Eighth A&R credit facility are secured by first priority liens on substantially all of the Company’s and its material operating subsidiaries’ oil and natural gas properties and associated assets and all of the stock of our material operating subsidiaries that are guarantors of the Eighth A&R credit facility. Additionally, SRII Opco, LP (“SRII Opco LP”), a Delaware limited partnership and Alta Mesa Holdings GP, LLC, a Texas limited liability company (“AMH GP”) will pledge their respective limited partner interests in us as security for our obligations. If an event of default occurs under the Eighth A&R credit facility, the administrative agent will have the right to proceed against the pledged capital stock and take control of substantially all of our assets and our material operating subsidiaries that are guarantors.
The Eighth A&R 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 its organizational documents, incur liens and engage in certain other transactions without the prior consent of the lenders. The Eighth A&R credit facility permits us to make distributions to any parent entity (i) to pay for reimbursement of third party costs and expenses that are general and administrative expenses incurred in the ordinary course of business by such parent entity or (ii) in order to permit such parent entity to (x) make permitted tax distributions and (y) pay the obligations under the Tax Receivable Agreement (as defined below).
The Eighth A&R credit facility also requires us to maintain the following two financial ratios:
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a current ratio, tested quarterly, commencing with the fiscal quarter ending June 30, 2018, 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
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a leverage ratio, tested quarterly, commencing with the fiscal quarter ending June 30, 2018, of our consolidated debt (other than obligations under hedge agreements) as of the end of such fiscal quarter to our consolidated earnings before interest, taxes, depreciation, depletion, amortization and exploration expenses (“EBITDAX”) annualized by multiplying EBITDAX for the period of (A) the fiscal quarter ending June 30, 2018 times 4, (B) the two fiscal quarter periods ending September 30, 2018 times 2 and (C) the three fiscal quarter periods ending December 31, 2018 times 4/3rds and (D) for each fiscal quarter on or after March 31, 2019, EBITDAX times 4/4, of not greater than 4.0 to 1.0.
At the execution of the Eighth A&R credit facility and in connection with the closing of the business combination, we are not subject to financial covenants ratios as of December 31, 2017. We will be required to maintain financial ratios commencing on the fiscal quarter ending June 30, 2018.
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Senior Secured Term Loan. On June 2, 2015, we entered into a second lien senior secured term loan agreement (the “term loan facility”) with Morgan Stanley Energy Capital Inc., as administrative agent, and the lenders party thereto, pursuant to which we borrowed $125 million. In October 2016, High Mesa contributed $300 million to us from the investment by Bayou City, as described in Note 17 - Partners’ Capital. We used a portion of the contribution to repay all amounts outstanding under the term loan facility of $127.7 million, which includes accrued interest and a $2.5 million prepayment premium for repaying all amounts owed under the term loan facility prior to maturity date.
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For the year ended December 31, 2016, the Company recognized a loss of $4.7 million, which included unamortized deferred financing cost write-offs of $2.0 million, which is reflected in loss on extinguishment of debt in the consolidated statements of operations.
Senior Unsecured Notes. On December 8, 2016, the Company and our wholly owned subsidiary Alta Mesa Finances Services Corp. (collectively, the “Issuers”) 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 the Company of $491.3 million, after deducting commission offering expenses. The Company used the proceeds from the issuance of the 2024 Notes to fund the repurchase of the $450 million senior unsecured notes (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 credit facility. The 2024 Notes were issued in a private placement but were exchanged for substantially identical registered senior notes in November 2017.
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, the Company 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, the Company 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 occurrence of certain kinds of change of control, each holder of the 2024 Notes may require the Company 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, the Company 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 are fully and unconditionally guaranteed on a senior unsecured basis by each of our material subsidiaries, subject to certain customary release provisions. Accordingly, they will rank equal in right of payment to all of the Company’s existing and future senior indebtedness; senior in right of payment to all of the Company’s existing and future indebtedness that is expressly subordinated to the 2024 Notes or the respective guarantees; effectively subordinated to all of the Company’s existing and future secured indebtedness to the extent of the value of the collateral securing such indebtedness, including amounts outstanding under the Company’s credit facility; and structurally subordinated to all existing and future indebtedness and obligations of any of the Company’s subsidiaries that do not guarantee the 2024 Notes.
The 2024 Notes contain certain covenants limiting the Issuers’ ability and the ability of the Restricted Subsidiaries (as defined in the indenture) 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 the Company’s line of business.
The closing of the business combination did not constitute as a change of control under the indenture governing the 2024 Notes because certain existing owners of the Company and SRII Opco LP entered into an amended and restated voting agreement with respect to the voting interests in AMH GP. See Note 19 - Subsequent Events for further detail.
Repurchase and Redemption of 9.625% Senior Unsecured Notes due 2018
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, on December 8, 2016, the Company 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 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 the obligations of the Company thereunder. As a result of the tender offer and redemption, the Company repurchased and redeemed its $450 million outstanding 2018 Notes for an aggregate cost of $459.4 million, including accrued interest and fees, for the year ended December 31, 2016.
For the year ended December 31, 2016, the Company recognized a loss of $13.5 million, which includes unamortized discount write-off of $0.9 million, unamortized deferred financing costs write-off of $3.2 million, tender premium of $2.5 million and accrued interest of $6.9 million, which is all reflected in loss on extinguishment of debt in the consolidated statements of operations.
Notes Payable to Founder. We have notes payable to our founder which bear simple interest at 10% with a balance of $28.2 million and $27.0 million at December 31, 2017 and December 31, 2016, respectively. The maturity date was extended on March 25, 2014, from December 31, 2018 to December 31, 2021. Interest and principal are payable at maturity.
These founder notes are unsecured and are subordinate to all debt. The founder notes are also subordinated to the rights of the AM Contributor and Riverstone VI Alta Mesa Holdings, L.P. (“Riverstone”) to receive distributions under our Amended Partnership Agreement and subordinated to the rights of the holders of Series B preferred stock of High Mesa to receive payments. Subsequent to year end, our founder converted the founder notes into equity interests in the AM Contributor immediately prior to the closing of the business combination with AMR. See Note 19 - Subsequent Events for further details.
Interest on the notes payable to our founder amounted to $1.2 million during each of the years ended December 31, 2017, 2016 and 2015. Such amounts have been added to the balance of the founder notes.
Deferred financing costs. As of December 31, 2017, the Company had $11.4 million of deferred financing costs related to the credit facility and the 2024 Notes, which are being amortized over the respective terms of the related debt instrument. Deferred financing costs of $9.6 million related to the 2024 Notes are included in long-term debt on the consolidated balance sheets as of December 31, 2017. Deferred financing costs of $1.8 million related to the credit facility are included in deferred financing costs, net on the consolidated balance sheets at December 31, 2017. Amortization of deferred financing costs recorded for the years ended December 31, 2017, 2016 and 2015 was $2.7 million, $3.9 million and $3.4 million, respectively. These costs are included in interest expense on the consolidated statements of operations. The loss on extinguishment of debt in the consolidated statements of operations included unamortized deferred financing costs write-offs of $5.1 million related to the repayment of the term loan facility and the repurchase and redemption of the 2018 Notes for the year ended December 31, 2016.
Future maturities of long-term debt, including the notes payable to our founder and excluding unamortized deferred financing costs, at December 31, 2017 are as follows (in thousands):
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(1)
As discussed above, subsequent to year-ended December 31, 2017, we entered into the Eighth A&R credit facility which extended the maturity date on the credit facility to February 9, 2023.
(2)
As discussed above, our founder notes were converted into equity interests in AM Contributor subsequent to year-ended December 31, 2017.
The credit facility and the 2024 Notes contain customary events of default. If an event of default occurs and is continuing, the holders of such indebtedness may elect to declare all the funds borrowed to be immediately due and payable with accrued and unpaid interest. Borrowings under other debt instruments that contain cross-acceleration or cross-default provisions may also be accelerated and become due and payable.
As of December 31, 2017, the covenants of the Company’s senior secured revolving credit facility prohibit it from making any distributions. At December 31, 2017, we were in compliance with the covenants of the 2024 Notes.
NOTE 12 - ACCOUNTS PAYABLE AND ACCRUED LIABILITIES
The following provides the detail of accounts payable and accrued liabilities:
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NOTE 13 - COMMITMENTS AND CONTINGENCIES
Contingencies
Environmental claims: Various landowners have sued the Company and/or our wholly owned subsidiaries, in lawsuits concerning several fields in which we have or 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 our 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 consolidated financial statements at December 31, 2017.
Title/lease disputes: Title and lease disputes may arise in the normal course of our operations. These disputes have historically been small but could result in an increase or decrease in reserves and/or other forms of settlement, such as cash, once a final resolution to the title dispute is made.
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, 2017, we have accrued approximately $2.5 million ($0.8 million in current
			
		
			
		
liabilities and $1.7 million in other long-term liabilities) in connection with the settlement. The settlement requires payment over the term of six years.
On January 25, 2017, Bollenbach Enterprises Limited Partnership filed a class action petition in Kingfisher County, Oklahoma against Oklahoma Energy Acquisitions, LP, our wholly owned subsidiary, Alta Mesa Services, LP, our wholly owned subsidiary, and us (collectively, the “AMH Parties”) claiming royalty underpayment or non-payment of royalty. The suit alleges that the AMH Parties made improper deductions that resulted in underpayment of royalties on natural gas and/or constituents of the gas stream produced from wells. The case was moved to federal court and stayed by the court pending the parties’ efforts to settle the case. In June 2017, the court administratively closed the case following mediation. Class settlement requires approval of the court after certain lengthy notice periods. As of December 31, 2017, we accrued approximately $4.7 million in accounts payable and accrued liabilities in our consolidated balance sheets in connection with this litigation. The settlement expense is recorded in general and administrative (“G&A”) in our consolidated statement of operations and was paid subsequent to year end.
On March 1, 2017, Mustang Gas Products, LLC (“Mustang”) filed suit in the District Court of Kingfisher County, Oklahoma, against Oklahoma Energy Acquisitions, LP, and eight other entities, including us. Mustang alleges that (1) Mustang is a party to gas purchase agreements with Oklahoma Energy containing gas dedication covenants that burden land, leases and wells in Kingfisher County, Oklahoma, and (2) Oklahoma Energy, in concert with the other defendants, has wrongfully diverted gas sales to us in contravention of these agreements. Mustang asserts claims for declaratory judgment, anticipatory repudiation and breach of contract against Oklahoma Energy only. Mustang also claims tortious interference with contract, conspiracy, and unjust enrichment/constructive trust against all defendants, including us. While we may incur costs or losses in connection with this litigation, we have not accrued a loss contingency because we are currently unable to determine the scope or merit of Mustang’s claim or to reasonably estimate an amount or range of such costs or losses. We believe that the allegations contained in this lawsuit are without merit and intend to vigorously defend ourselves.
Other contingencies: We are subject to legal proceedings, claims and liabilities arising in the ordinary course of business. The outcome cannot be reasonably estimated; however, in the opinion of management, such litigation and claims will be resolved without material adverse effect on our financial position, results of operations or cash flows. Accruals for losses associated with litigation are made when losses are deemed probable and can be reasonably estimated.
We have a contingent commitment to pay an amount up to a maximum of approximately $2.2 million for properties acquired in 2008. The additional purchase consideration will be paid if certain product price conditions are met.
Performance appreciation rights: In the third quarter of 2014, we adopted the Alta Mesa Holdings, LP Amended and Restated Performance Appreciation Rights Plan (the “Plan”), effective September 24, 2014. The Plan is intended to provide incentive compensation to key employees and consultants who make significant contributions to the Company. Under the Plan, participants are granted Performance Appreciation Rights (“PARs”) with a stipulated initial designated value (“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 the initial stipulated value 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 Plan, but generally can be construed in accordance with the meaning of the term “change in control event”) or as selected by the participant, but no earlier than five years from the end of the year of the grant. Both the initial stipulated value and the designated payment value of the PAR are determined by the Plan’s administrative committee, composed of members of our board of directors. 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 Plan) from the liquidity event. After any payment valuation date, regardless of payment or none, vested PARs expire. During 2017, we granted 308,800 PARs and terminated 5,280 PARs with a SIDV of $40, resulting in 880,420 PARs issued at a weighted average value of $37.90. We consider the possibility of payment at a fixed determination date absent a positive liquidity event to be remote. Therefore, we have not provided any amount for this contingent liability in our consolidated financial statements at December 31, 2017 or 2016.
Subsequent to year end, the business combination with AMR resulted in the accelerated vesting and payment of all outstanding PARs. The value of the PARs that vested upon the closing was approximately $10.6 million.
Commitments
Office and Equipment Leases: We lease office space, as well as certain field equipment such as compressors, under long-term operating lease agreements. The lease for our main office will expire in 2022. Any initial rent-free months are amortized over the life of the lease. Equipment leases are generally for two years or less. Total rent expense, net of sublease income, including office space and compressors, for the years ended December 31, 2017, 2016, and 2015 amounted to approximately $10.3 million, $5.7 million, and $4.8 million, respectively.
			
		
			
		
At December 31, 2017, the future minimum base rentals for non-cancelable operating leases are as follows:
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(1)
These amounts include long-term lease payments for office space and compressors, net of sublease income. The Company expects to receive $0.1 million of total sublease income through 2019.
Additionally, at December 31, 2017, the Company had posted bonds in the aggregate amount of $17.4 million, primarily to cover future abandonment costs.
NOTE 14 - SIGNIFICANT CONCENTRATIONS
We sell our oil and natural gas primarily through a marketing contract with AEM. AEM is our marketing agent and acts on our behalf to market our oil and natural gas to any purchasers identified by AEM. Until the closing of the business combination, we were 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. The fee charged to us by AEM for marketing is recorded as a marketing and transportation expense. Our marketing agreement with AEM commenced in June 2013. This agreement will terminate in June 2018, with additional provisions for extensions beyond five years and for early termination. AEM marketed the majority of our production from operated fields between 2015 and 2017. Production from non-operated fields was marketed on our behalf by the operators of those properties.
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For the year ended December 31, 2017, revenues marketed by AEM were $199.2 million, or approximately 70.9% of total revenue excluding hedging activities. For the year ended December 31, 2016, revenues marketed by AEM were $114.8 million, or approximately 74.0% of total revenue excluding hedging activities. For the year ended December 31, 2015, revenues marketed by AEM were $108.5 million, or approximately 54.9% of total revenue excluding hedging activities.
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Based on revenues excluding hedging activities, one major customer, our related party, Kingfisher accounted for 10% or more of our revenues, with revenues excluding hedging activities of $34.2 million or approximately 12% of total revenues. 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.
NOTE 15 - 401(k) SAVINGS PLAN
Employees of Alta Mesa Services, LP, our wholly owned subsidiary (“Alta Mesa Services”), and Petro Operating Company, LP (“POC”) may participate in a 401(k) savings plan, whereby the employees may elect to make contributions pursuant to a salary reduction agreement. Alta Mesa Services and POC make a matching contribution equal to 100% of an employee’s salary deferral contribution up to a maximum of 5% of an employee’s salary, effective January 1, 2016. Matching contributions to the plan were approximately $1,227,000, $1,122,000, and $710,000 for the years ended December 31, 2017, 2016 and 2015, respectively.
NOTE 16 - SIGNIFICANT RISKS AND UNCERTAINTIES
Our business makes us vulnerable to changes in wellhead prices of oil and natural gas. Historically, world-wide oil and natural gas prices and markets have been volatile, and may continue to be volatile in the future. In particular, the prices of oil and natural gas have been highly volatile and declined dramatically since the second half of 2014. Prices for oil and natural gas can fluctuate widely in response to relatively minor changes in the global and regional supply of and demand for oil and natural gas, as well as market uncertainty, economic conditions and a variety of additional factors. Although oil and natural gas prices have increased from the lows experienced since the decline in the second half of 2014, forecasted prices for both oil and natural gas have remained lower than levels
			
		
			
		
seen in recent years. The duration and magnitude of changes in oil and natural gas prices cannot be predicted. Continued low 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 oil and natural gas reserves. Sustained low oil or natural gas prices may require us to further write down the value of our oil and natural gas properties and/or revise our development plans, which may cause certain of our undeveloped well locations to no longer be deemed proved. This could cause a reduction in the borrowing base under our credit facility to the extent that we are not able to replace the reserves that we produce. Low prices may also reduce our cash available for distribution, acquisitions and for servicing our indebtedness. We mitigate some of this vulnerability by entering into oil and natural gas price derivative contracts. See Note 8.
NOTE 17 - PARTNERS’ CAPITAL
Management and Control: Our business and affairs are managed by Alta Mesa Holdings GP, LLC, our general partner (“General Partner” or “AMH GP”).
On August 31, 2016, our Class B partner at the time completed the sale of preferred stock to BCE-MESA Holdings LLC (“BCE-MESA”), a fund managed by Bayou City. In connection with the sale of preferred stock, our General Partner, Class B partner at the time, and all of our Class A partners at the time entered into a Fourth Amended and Restated Limited Partnership Agreement (the “Fourth Amended Partnership Agreement”). The Fourth Amended Partnership Agreement provides, among other things, for certain drag-along rights, including the mandatory contribution to the Class B partner at the time by the Class A partners at the time of their remaining Class A units upon an initial public offering.
In addition, on August 31, 2016, the owners of our General Partner entered into a Third Amended and Restated Limited Liability Company Agreement, which was amended to provide that the number of members of the board of managers of our General Partner be increased to match the number of members of the board of directors of our Class B partner. William W. McMullen, the founder and managing partner of Bayou City, was appointed to the board of managers of our General Partner at that time.
On September 30, 2016, our Class B partner completed an additional sale of preferred stock to Bayou City. In connection with this investment, Mark Stoner, as a nominee of Bayou City, was appointed to the board of managers of our General Partner.
On August 16, 2017, our General Partner, the AM Contributor and Riverstone entered into the Sixth Amended and Restated Agreement of Limited Partnership (the “Sixth Amended Partnership Agreement”). The Sixth Amended Partnership Agreement reflected, among other things, certain changes in our ownership, and provides for certain preemptive rights, tag-along rights, and drag-along rights for the limited partners. In connection with the Sixth Amended Partnership Agreement, our limited partners at the time transferred their interests in us to the AM Contributor. The Sixth Amended Partnership Agreement also reflects the admission of Riverstone and the AM Contributor to the Company as limited partners, and provides for certain distribution rights for the Class A and Class B Limited Partners (as defined therein) with respect to the STACK and non-STACK assets.
Riverstone was admitted as a limited partner in connection with its $200 million capital contribution to us on August 17, 2017, in exchange for limited partner interests in us with respect to the economic rights to the STACK assets. We used all of the capital contribution to pay down our credit facility.
On August 16, 2017, the owners of our General Partner entered into a Fifth Amended and Restated Limited Liability Company Agreement, which was amended to, among other things, show certain changes in the ownership of our General Partner and reflect that the holders of Class A Units (as defined therein) are entitled to 100% of the economic rights with respect to our General Partner and the holders of Class B Units (as defined therein) are entitled to 100% of the voting rights with respect to our General Partner.
In connection with the closing of the business combination on February 9, 2018, our General Partner and SRII Opco LP entered into a Seventh Amended and Restated Agreement of Limited Partnership of Alta Mesa (the “Seventh Amended Partnership Agreement”). The Seventh Amended Partnership Agreement reflects, among other things, that SRII Opco LP is now our sole limited partner.
In connection with the closing of the business combination on February 9, 2018, the owners of our General Partner entered into a Sixth Amended and Restated Limited Liability Company Agreement, which was amended to, among other things, reflect that SRII Opco LP owns all of the Class A Units (as defined therein) and 90% of the Class B Units (as defined therein).
Contribution, Distribution, and Income Allocation: The Seventh Amended Partnership Agreement specifies the manner in which we will make cash distributions to our partners. When AMH GP so directs, the Partnership shall make distributions of Net Cash Flow (as defined therein) to the limited partners pro rata.
In connection with the final sale of preferred stock to Bayou City during the fourth quarter of 2016, our Class B partner contributed $300 million from the Bayou City investment to us. We used a portion of the contribution to repay all amounts outstanding under the
			
		
			
		
term loan facility of $127.7 million, which includes accrued interest and a $2.5 million prepayment premium for repaying all amounts owed under the term loan facility prior to maturity date. The remaining funds are available to be used for general corporate purposes.
As described in Notes 4 and 10, High Mesa purchased from BCE and contributed interests in 24 producing wells drilled under the joint development agreement to us on December 31, 2016. High Mesa’s equity contribution was recorded at the contribution date 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.
During 2015, our partnership agreement was amended and restated, pursuant to which our Class B partner contributed $20 million to us, which we used to pay down amounts owed under the credit facility.
We made no distributions for the years ended December 31, 2017 and 2016. For the year ended December 31, 2015, we made distributions of approximately $3.8 million to our Class B partner.
NOTE 18 - SUBSIDIARY GUARANTORS
All of our material wholly-owned subsidiaries are guarantors under the terms of our senior notes and our credit facility. Our consolidated financial statements reflect the combined financial position of these subsidiary guarantors. The parent company, Alta Mesa Holdings, LP, has no independent operations, assets, or liabilities. The guarantees are full and unconditional (except for customary release provisions) and joint and several. Those subsidiaries which are not wholly owned and are not guarantors and minor. There are no restrictions on dividends, distributions, loans, or other transfers of funds from the subsidiary guarantors to the parent company.
NOTE 19 - SUBSEQUENT EVENTS
Contribution Agreement
On August 16, 2017, we entered into a Contribution Agreement (the “AM Contribution Agreement”) with Alta Mesa Resources, Inc. (formerly Silver Run Acquisition Corporation II, a Delaware corporation (“AMR”)), High Mesa Holdings, LP, a Delaware limited partnership (the “AM Contributor”), High Mesa Holdings GP, LLC, a Texas limited liability company and the sole general partner of the AM Contributor, our General Partner, and, solely for certain provisions therein, the equity owners of the AM Contributor. Simultaneous with the execution of the AM Contribution Agreement, AMR entered into (i) a Contribution Agreement (the “KFM Contribution Agreement”) with KFM Holdco, LLC, a Delaware limited liability company (the “KFM Contributor”), Kingfisher Midstream, LLC, a Delaware limited liability company (“Kingfisher”), and, solely for certain provisions therein, the equity owners of the KFM Contributor; and (ii) a Contribution Agreement (the “Riverstone Contribution Agreement” and, together with the AM Contribution Agreement and the KFM Contribution Agreement, the “Contribution Agreements”) with Riverstone VI Alta Mesa Holdings, L.P., a Delaware limited partnership (the “Riverstone Contributor”).
On February 9, 2018 (the “Closing Date”), we consummated the transactions contemplated by the Contribution Agreements and SRII Opco LP, acquired (a) (i) all of the limited partner interests in us and (ii) 100% of the economic interests and 90% of the voting interests in AMH GP (with (i) and (ii) collectively, the “AM Contribution”) and (b) 100% of the economic interests in Kingfisher (the “Kingfisher Contribution”). The acquisition of us and Kingfisher pursuant to the Contribution Agreements is referred to herein as the “business combination” and the transactions contemplated by the Contribution Agreements are referred to herein as the “Transactions.”
SRII Opco GP, LLC, a Delaware limited liability company (“SRII Opco GP”), the sole general partner of SRII Opco LP, is a wholly owned subsidiary of AMR. The limited partners of SRII Opco LP are the AM Contributor, the KFM Contributor and the Riverstone Contributor (collectively, the “Contributors”), AMR and certain funds managed by HPS Investment Partners, LLC, a Delaware limited liability company (“Highbridge”). As a result of the Transactions, AMR has obtained control over the management of AMH GP and, consequently, us. AMR is a publicly traded corporation that is not under the control of any person. Prior to the closing of the Transactions, AMH GP, and consequently, us, was controlled by High Mesa and indirectly by our Chief Operating Officer, Michael E. Ellis.
Harlan H. Chappelle, our Chief Executive Officer and a director, Michael Ellis, our Chief Operating Officer and a director and certain affiliates of Bayou City, and Highbridge, continue to own an aggregate 10% voting interest in AMH GP following the closing. These existing owners were a party to a voting agreement with the Alta Mesa Contributor and AMH GP, pursuant to which they agreed to vote their interests in AMH GP as directed by the AM Contributor. In connection with the closing of the Transactions, the parties amended and restated the voting agreement to include SRII Opco LP as a party and the existing owners agreed to vote their interests in AMH GP as directed by SRII Opco LP and appoint SRII Opco LP as their respective proxy and attorney-in-fact with respect to any voting matters related to their respective interests in AMH GP. The amended and restated voting agreement will continue in force until
			
		
			
		
SRII Opco LP elects to terminate the agreement or, with respect to each existing owner individually, such existing owner no longer owns a voting interest in AMH GP. The closing of the business combination did not constitute a change of control under the indenture governing our 2024 Notes.
Consideration
Pursuant to the AM Contribution Agreement, at the closing of the Transactions (the “Closing”), the AM Contributor received 138,402,398 common units representing limited partner interests (the “Common Units”) in SRII Opco LP. The AM Contributor also acquired from AMR a number of newly issued shares of non-economic capital stock of AMR, designated as Class C common stock, par value $0.0001 per share (the “Class C Common Stock”), corresponding to the number of Common Units received by the AM Contributor at the Closing.
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In addition to the above, for a period of seven years following the Closing, the AM Contributor will be entitled to receive an aggregate of up to $800 million in earn-out consideration to be paid in the form of Common Units (and acquire a corresponding number of shares of Class C Common Stock) as specified below if the 20-day volume-weighted average price (“20-Day VWAP”) of the Class A Common Stock equals or exceeds the following prices (each such payment, an “Earn-Out Payment”):
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The AM Contributor will not be entitled to receive a particular Earn-Out Payment on more than one occasion and, if, on a particular date, the 20-Day VWAP entitles the AM Contributor to more than one Earn-Out Payment (each of which has not been previously paid), the AM Contributor will be entitled to receive each such Earn-Out Payment. The AM Contributor will be entitled to the earn-out consideration described above in connection with certain liquidity events of AMR, including a merger or sale of all or substantially all of AMR’s assets, if the consideration paid to holders of Class A Common Stock in connection with such liquidity event is greater than any of the above-specified 20-Day VWAP hurdles.
AMR also contributed $554 million in cash to us at the closing. We used a portion of the amount to repay the outstanding balances under the senior secured revolving credit facility. AMR’s source for these funds was from the sale of its securities to investors in a public offering and in private placements.
The business combination resulted in the accelerated vesting and payment of all outstanding PARs and deferred compensation plans at the time of close. The value of the PARs and deferred compensation plan that vested was approximately $25.1 million.
Management Services Agreement-High Mesa
In connection with the Closing, we entered into a management services agreement (the “High Mesa Agreement”) with High Mesa with respect to our non-STACK assets that were distributed to High Mesa’s subsidiary in connection with the business combination. Under the High Mesa Agreement, during the 180-day period following the Closing (the “Initial Term”), we will provide certain administrative, management and operational services necessary to manage the business of High Mesa and its subsidiaries (the “Services”), in each case, subject to and in accordance with an approved budget. Thereafter, the High Mesa Agreement shall automatically renew for additional consecutive 180-day periods (each a “Renewal Term”), unless terminated by either party upon at least 90-days written notice to the other party prior to the end of the Initial Term or any Renewal Term. For a period of 60 days following the expiration of the term, we are obligated to assist High Mesa with the transition of the Services from Alta Mesa to a successor service provider. As compensation for the Services, including during any transition to a successor service provider, High Mesa will pay us each month (i) a management fee of $10,000, (ii) an amount equal to our costs and expenses incurred in connection with providing the Services as provided for in the approved budget and (iii) an amount equal to our costs and expenses incurred in connection with any emergency.
We are obligated to provide the Services in accordance with reasonable and prudent practices, as relevant to the Services, of the oil and natural gas industry, and in material compliance with all applicable laws; provided that we will only be liable under the High Mesa Agreement for its own gross negligence, willful misconduct and/or fraud. We are only obligated to provide the Services under the High Mesa Agreement to the extent that High Mesa has provided the funds necessary to undertake such Services.
Under the High Mesa Agreement, High Mesa will have customary audit rights that will survive the termination or expiration of the High Mesa Agreement. High Mesa and we will each have the right to terminate the High Mesa Agreement prior to the expiration of the term (i) in the event of a sale or change of control of the other party, (ii) following an event related to bankruptcy of either party or
			
		
			
		
(iii) following the other party’s material breach. In addition, High Mesa will have the right to terminate the High Mesa Agreement prior to the expiration of the term upon a sale or change of control of High Mesa.
Management Services Agreement-Kingfisher
In connection with the Closing, we entered into a management services agreement (the “Kingfisher Agreement”) with Kingfisher. Under the Kingfisher Agreement, we will provide certain administrative, management and operational services necessary to manage the business of Kingfisher and its subsidiaries (the “Services”). As compensation for the Services, Kingfisher will pay us each month (i) a management fee of $10,000 and (ii) an amount equal to our costs and expenses incurred in connection with providing the Services.
We are obligated to provide the Services in accordance with reasonable and prudent practices, as relevant to the Services, of the oil and natural gas industry, and in material compliance with all applicable laws; provided that we will only be liable under the Kingfisher Agreement for its own gross negligence, willful misconduct and/or fraud. Under the Kingfisher Agreement, Kingfisher will have customary audit rights that will survive the termination or expiration of the Kingfisher Agreement.
Amended Limited Partnership and Limited Liability Company Agreements
In connection with the Closing, AMH GP and SRII Opco LP entered into a Seventh Amended and Restated Agreement of Limited Partnership of Alta Mesa (the “Seventh Amended Partnership Agreement”). The Seventh Amended Partnership Agreement reflects, among other things, that SRII Opco LP is now the sole limited partner of Alta Mesa.
In addition, on February 9, 2018, the owners of AMH GP entered into a Sixth Amended and Restated Limited Liability Company Agreement of AMH GP (the “Sixth Amended LLC Agreement”), which was amended to, reflect that SRII Opco LP, now the holder of all of the Class A Units (as defined therein) is entitled to 100% of the economic rights with respect to AMH GP, and that SRII Opco LP is now the holder of 90% of the Class B Units (as defined therein) which are entitled to 100% of the voting rights with respect to AMH GP.
As described above, on February 9, 2018, all of the owners of Alta Mesa GP entered into an amended and restated voting agreement (the “Voting Agreement”) regarding the voting of their interests in Alta Mesa GP.
Voting Agreement
Certain existing owners of the Company, including our Chief Executive Officer Harlan H. Chappelle, Chief Operating Officer Michael E. Ellis and certain affiliates of Bayou City and Highbridge, own an aggregate 10% voting interest in AMH GP and will continue to own such interest following the Closing. These existing owners were a party to a voting agreement with the AM Contributor and AMH GP, pursuant to which they have agreed to vote their interests in AMH GP as directed by the AM Contributor. In connection with the Closing, the parties amended and restated the voting agreement to include SRII Opco LP as a party and the existing owners agreed to vote their interests in AMH GP as directed by SRII Opco LP and appoint SRII Opco LP as their respective proxy and attorney-in-fact with respect to any voting matters related to their respective interests in AMH GP. The voting agreement will continue in force until SRII Opco LP elects to terminate the agreement or, with respect to each existing owner individually, such existing owner no longer owns a voting interest in AMH GP.
Appointment and Departure of Directors
In connection with the Closing, Michael A. McCabe, Homer “Gene” Cole, Mickey Ellis, Don Dimitrievich, William W. McMullen and Mark Stoner resigned from the board of AMH GP. In connection with the business combination, James T. Hackett was appointed to the board of AMH GP. Harlan H. Chappelle and Michael E. Ellis remain directors on the board of AMH GP. Our executive management team remains the same, except that Mr. Hackett is now Chairman of the Board.
Distribution of Non-Stack Assets
In connection with the Closing, we have completed our transition from a diversified asset base composed of a portfolio of conventional assets to an oil and liquids-rich resource play in the STACK. On February 8, 2018, we distributed the remainder of our non-STACK assets to the AM Contributor as a dividend. At the time of the disposition, management estimated the carrying value of our remaining non-STACK assets to be $42.8 million with liabilities of $52.5 million, which liabilities include $44.6 million of asset retirement obligations.
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NOTE 20 - SUPPLEMENTAL QUARTERLY INFORMATION (Unaudited)
Results of operations by quarter for the year ended December 31, 2017 were:
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(1)
Includes $1.2 million, $27.9 million, and $1.1 million of impairment expense during the quarters ended March 31, 2017, June 30, 2017, and December 31, 2016, respectively.
(2)
Includes $18.3 million gain on derivative contracts during quarter ended June 30, 2017, $10.5 million and $29.7 million loss on derivative contracts during the quarters ended September 30, 2017 and December 31, 2017.
(3)
Includes $22.2 million loss on the sale of the Weeks Island field during the quarter ended December 31, 2017.
Results of operations by quarter for the year ended December 31, 2016 were:
(4)
Includes $1.8 million, $11.6 million, and $2.1 million of impairment expense during the quarters ended March 31, 2016, June 30, 2016, and December 31, 2016, respectively.
(5)
Includes $38.3 million and $16.5 million loss on derivative contracts during the quarters ended June 30, 2016 and December 31, 2016, respectively.
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NOTE 21 - SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES (Unaudited)
The unaudited reserve and other information presented below is provided as supplemental information in accordance with the provisions of ASC Topic 932-235. The information presented includes amounts related to discontinued operations.
Oil and natural gas producing activities are conducted onshore within the continental United States and all of our proved reserves are located within the United States.
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Estimated Quantities of Proved Reserves
The following table sets forth our net proved reserves as of December 31, 2017, 2016 and 2015, and the changes therein during the years then ended. Proved oil and natural gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made.
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(1)
Purchases in place includes 3.1 MMBoe of reserves related to the Contributed Wells from our Class B partner. See Note 10 - Related Party Transactions and Note 17 - Partners’ Capital for further details.
Capitalized Costs Relating to Oil and Natural Gas Producing Activities
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(1)
Capitalized costs includes amounts related to the Weeks Island field.
			
		
			
		
Costs Incurred in Oil and Natural Gas Acquisition, Exploration and Development Activities
Acquisition costs in the table below include costs incurred to purchase, lease, or otherwise acquire property. Exploration expenses include additions to exploratory wells, including those in progress, and other exploration expenses, such as geological and geophysical costs. Development costs include additions to production facilities and equipment and additions to development wells, including those in progress.
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(1)
Property acquisition costs in unproved properties in 2017 include the acquisition of unevaluated leasehold portion from an unaffiliated third-party of approximately $45.6 million. Property acquisition costs in unproved properties in 2015 include the unevaluated leasehold portion of the Kingfisher leasehold acquisition of $46.6 million.
(2)
Property acquisition costs in the proved properties in 2016 include the Contributed Wells by our former Class B partner to us of $65.7 million.
(3)
Includes asset retirement additions (revisions) of $4.4 million, $1.9 million, and $(0.3) million for the years ended December 31, 2017, 2016 and 2015, respectively.
(4)
Cost incurred includes amounts related to the Weeks Island field, which we sold in the fourth quarter of 2017 and classified as discontinued operations. See Note 6 - Discontinued operations for further details.
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Standardized Measure of Discounted Future Net Cash Flows
The information that follows has been developed pursuant to ASC 932-235 and utilizes reserve and production data prepared by us. Reserve estimates are inherently imprecise and estimates of new discoveries are less precise than those of producing oil and natural gas properties. Accordingly, these estimates are expected to change as future information becomes available.
Future cash inflows as of December 31, 2017, 2016 and 2015 were calculated using an un-weighted arithmetic average of oil and natural gas prices in effect on the first day of each month in the respective year, except where prices are defined by contractual arrangements. Operating costs, production and ad valorem taxes and future development costs are based on current costs with no escalation.
Actual future prices and costs may be materially higher or lower. Actual future net revenues also will be affected by factors such as actual production, supply and demand for oil and natural gas, curtailments or increases in consumption by natural gas purchasers, changes in governmental regulations or taxation and the impact of inflation on costs.
			
		
			
		
The following table sets forth the components of the standardized measure of discounted future net cash flows at December 31, 2017, 2016 and 2015:
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No consideration was given to the Company’s hedged transactions. The estimated realized prices for natural gas liquids using a $51.34 per Bbl benchmark and adjusted for average differentials were $26.06. Natural gas liquid prices vary depending on the composition of the natural gas liquids basket and current prices for various components thereof, such as butane, ethane, and propane, among others.
			
		
			
		
Changes in Standardized Measure of Discounted Future Net Cash Flows
The following table sets forth the changes in standardized measure of discounted future net cash flows:
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