Index to Financial Statements

If any of the securities being registered on this Form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box. ☐

If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. ☐

If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. ☐

If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. ☐

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

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 7(a)(2)(B) of the Securities Act. ☒

CALCULATION OF REGISTRATION FEE



Title Of Each Class of Securities To Be Registered	Proposed Maximum Aggregate Offering Price (1)(2)	Amount of Registration Fee
Common stock, par value $0.01 per share	$100,000,000	$11,590

(1)	Includes shares issuable upon exercise of the underwriters’ option to purchase additional shares of common stock from the selling stockholder.

(2)	Estimated solely for the purpose of calculating the registration fee pursuant to Rule 457(o) under the Securities Act of 1933, as amended.

The registrant hereby amends this Registration Statement on such date or dates as may be necessary to delay its effective date until the registrant shall file a further amendment that specifically states that this Registration Statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933, as amended, or until this Registration Statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.

The information in this prospectus is not complete and may be changed. These securities may not be sold until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities, and it is not soliciting an offer to buy these securities in any jurisdiction where the offer or sale is not permitted.

Subject to Completion, dated April 13, 2017

Preliminary Prospectus dated , 2017

PROSPECTUS

Shares

LOGO

Tapstone Energy Inc.

Common Stock

This is the initial public offering of our common stock. We are selling shares of our common stock.

Prior to this offering, there has been no public market for our common stock. The initial public offering price of the common stock is expected to be between $ and $ per share. We have applied to list our common stock on the New York Stock Exchange (the “NYSE”) under the symbol “TE”.

To the extent that the underwriters sell more than shares of common stock, the underwriters have the option to purchase up to an additional shares from the selling stockholder at the public offering price less the underwriting discount and commissions. If the underwriters exercise their option to purchase additional shares of common stock from the selling stockholder, we will not receive any proceeds from the sale of such shares by the selling stockholder.

We are an “emerging growth company” as that term is used in the Jumpstart Our Business Startups Act of 2012, and as such, we have elected to take advantage of certain reduced public company reporting requirements for this prospectus and future filings. See “Risk Factors” and “Summary—Our Company—Emerging Growth Company”.

Investing in our common stock involves risks. See “Risk Factors ” beginning on page 26.


	Per Share	Total
Public Offering Price	$	$
Underwriting Discounts and Commissions (1)	$	$
Proceeds to Tapstone Energy Inc. (before expenses)	$	$

(1)

The underwriters will also be reimbursed for certain expenses incurred in the offering. See “Underwriting (Conflicts of Interest)” for additional information regarding underwriting compensation.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

The underwriters expect to deliver the shares to purchasers on or about , 2017 through the book-entry facilities of The Depository Trust Company.

Book-Running Managers


BofA Merrill Lynch				Citigroup

The date of this prospectus is , 2017.

LOGO

TABLE OF CONTENTS


Summary			1
Risk Factors			26
Cautionary Statement Regarding Forward-Looking Statements			61
Use of Proceeds			63
Dividend Policy			64
Capitalization			65
Dilution			67
Selected Historical Consolidated Financial Data			69
Management’s Discussion and Analysis of Financial Condition and Results of Operations			73
Business			94
Corporate Reorganization			136
Management			139
Executive Compensation			145
Principal and Selling Stockholders			156
Certain Relationships and Related Party Transactions			158
Description of Capital Stock			162
Shares Eligible for Future Sale			167
Material U.S. Federal Income Tax Considerations for Non-U.S. Holders			169
Underwriting (Conflicts of Interest)			173
Legal Matters			181
Experts			181
Where You Can Find More Information			181
Index to Financial Statements			F-1
Annex A: Glossary of Oil and Natural Gas Terms			A-1

You should rely only on the information contained in this prospectus and any free writing prospectus prepared by us or on behalf of us or the information to which we have referred you. Neither we, the selling stockholder nor the underwriters have authorized anyone to provide you with information different from that contained in this prospectus and any free writing prospectus. We take no responsibility for, and can provide no assurance as to the reliability of, any other information that others may give you. We, the selling stockholder and the underwriters are offering to sell shares of common stock and seeking offers to buy shares of common stock only in jurisdictions where offers and sales are permitted. The information in this prospectus is accurate only as of the date of this prospectus, regardless of the time of delivery of this prospectus or any sale of the common stock. Our business, financial condition, results of operations and prospects may have changed since that date.

This prospectus contains forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond our control. Please read “Risk Factors” and “Cautionary Statement Regarding Forward-Looking Statements”.

Until , 2017 (25 days after commencement of this offering), all dealers that effect transactions in these securities, whether or not participating in this offering, may be required to deliver a prospectus. This is in addition to the dealer’s obligation to deliver a prospectus when acting as an underwriter and with respect to unsold allotments or subscriptions.

Commonly Used Defined Terms

As used in this prospectus, unless the context indicates or otherwise requires, the terms listed below have the following meanings:

•

“Tapstone”, the “Company”, “us”, “we”, “our” or “ours” or like terms refer to Tapstone Energy, LLC before the completion of our corporate reorganization described in “Corporate Reorganization” and to Tapstone Energy Inc. following the completion of our corporate reorganization;

•

“GSO” refers, as applicable, to GSO Capital Partners LP and its affiliates within the credit-focused business unit of The Blackstone Group L.P., including funds or accounts managed, advised or sub-advised by it or them, including GSO E&P Holdings I LP;

•

“Management Members” refers, collectively, to our current and former officers and employees who own equity interests in Tapstone Energy, LLC; and

•

“Existing Owners” refers, collectively, to GSO E&P Holdings I LP and the Management Members.

Industry and Market Data

The market data and certain other statistical information used throughout this prospectus are based on independent industry publications, government publications and other published independent sources. Although we believe these third-party sources are reliable as of their respective dates, neither we, the selling stockholder nor the underwriters have independently verified the accuracy or completeness of this information. Some data is also based on our good faith estimates. The industry in which we operate is subject to a high degree of uncertainty and risk due to a variety of factors, including those described in the section entitled “Risk Factors”. These and other factors could cause results to differ materially from those expressed in these publications.

Trademarks and Trade Names

We own or have rights to various trademarks, service marks and trade names that we use in connection with the operation of our business. This prospectus may also contain trademarks, service marks and trade names of third parties, which are the property of their respective owners. Our use or display of third parties’ trademarks, service marks, trade names or products in this prospectus is not intended to, and does not imply, a relationship with us or an endorsement or sponsorship by or of us. Solely for convenience, the trademarks, service marks and trade names referred to in this prospectus may appear without the ^®, TM or SM symbols, but such references are not intended to indicate, in any way, that we will not assert, to the fullest extent under applicable law, our rights or the right of the applicable licensor to these trademarks, service marks and trade names.

SUMMARY

This summary highlights information contained elsewhere in this prospectus. You should read the entire prospectus carefully, including the information under the headings “Risk Factors”, “Cautionary Statement Regarding Forward-Looking Statements” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the financial statements and the notes to those financial statements appearing elsewhere in this prospectus. The information presented in this prospectus assumes (i) an initial public offering price of $ per common share (the midpoint of the price range set forth on the cover of this prospectus) and (ii) unless otherwise indicated, that the underwriters do not exercise their option to purchase additional shares of common stock from the selling stockholder.

Unless indicated otherwise or the context otherwise requires, references in this prospectus to “Tapstone”, the “Company”, “us”, “we”, “our” or “ours” refer to Tapstone Energy, LLC before the completion of our corporate reorganization described in “Corporate Reorganization”, and to Tapstone Energy Inc. following the completion of our corporate reorganization. This prospectus includes certain terms commonly used in the oil and natural gas industry, which are defined elsewhere in this prospectus in the “Glossary of Oil and Natural Gas Terms”.

Our Company

Business Overview

We are a growth-oriented, independent oil and natural gas company focused on the development and production of oil and natural gas condensate resources in the Anadarko Basin in Oklahoma, Texas and Kansas. Our core development area is located in the northwest continuation of the geographic region commonly known as the STACK play in the Anadarko Basin (the “NW Stack”). We have a large, contiguous acreage position in the NW Stack that is characterized by significant operational control, multiple stacked benches and an extensive inventory of horizontal drilling locations that are expected to offer attractive single-well rates of return. We also own interests in legacy producing oil and natural gas properties in various fields located in the Anadarko Basin with long-lived reserves, predictable production profiles and limited capital expenditure requirements (our “legacy producing properties”). We are focused on maximizing stockholder value by (i) growing production, reserves and cash flow through the development of our multi-decade drilling inventory of over 2,700 gross operated identified horizontal drilling locations in the NW Stack, (ii) optimizing our operational, drilling and completion techniques and (iii) maintaining a disciplined financial strategy to pursue the development of our acreage in the NW Stack.

Tapstone was formed in December 2013 with funding by GSO Capital Partners LP (“GSO”), a subsidiary of The Blackstone Group L.P. (“Blackstone”), with the goal of building a premier oil and natural gas company focused on acquiring and developing producing oil and natural gas properties in the Anadarko Basin. Our management and technical teams have extensive engineering, geoscience, land, marketing and finance capabilities and have collectively participated in the drilling of over 10,000 horizontal wells across multiple unconventional plays in the lower 48 states. Our management team is led by Steven C. Dixon, our Chairman, President and Chief Executive Officer and an industry veteran with over 36 years of experience in managing, developing and growing oil and natural gas businesses in some of the most prolific oil and natural gas plays in the United States.

The NW Stack

experience operating in the area. In 2014 we began focusing specifically on the NW Stack after results in the SCOOP and STACK plays definitively showed a productive trend towards our current position in the NW Stack. We began assembling our acreage position through a grassroots leasing program that we commenced in September 2014. As a result of our early identification of the resource potential of the NW Stack, as well as the general weakness in the oil and gas industry at the time, we were able to assemble a large, contiguous block of acreage in the NW Stack, which we do not believe would be possible to replicate in today’s market. Our acreage position in the NW Stack consists of approximately 200,000 net acres in the adjacent Oklahoma counties of Dewey, Woodward, Ellis and Major.

As of December 31, 2016, we held the largest contiguous leasehold position in the NW Stack. We have identified five unique stacked benches within the NW Stack in the Meramec and Osage intervals that we refer to as the Upper Meramec, Middle Meramec, Lower Meramec, Upper Osage and Lower Osage. We have tested each of the five benches that we have identified over an area 40 miles east to west and 20 miles north to south across our acreage position, and we believe that each bench presents significant development potential and a sizable drilling inventory. As of December 31, 2016, we had identified over 2,700 gross operated horizontal drilling locations in the NW Stack, providing us with a multi-decade drilling inventory. We believe further upside potential may also exist in additional productive intervals within our acreage in the NW Stack.

Our acreage in the NW Stack has several attractive characteristics that include (i) thick gross pay across our acreage that ranges from approximately 1,000 to 1,500 feet, (ii) five identified stacked benches in the Meramec and Osage intervals, (iii) reservoir depths ranging from approximately 9,000 to 13,000 feet spanning both the oil and natural gas condensate windows and (iv) over-pressured and fractured reservoirs. These characteristics combine to provide strong well deliverability and attractive single-well rates of return.

We have accumulated a significant amount of technical information related to the reservoir potential across our acreage in the NW Stack. We have utilized this information to establish our geological model of the play. The information we have analyzed includes:

•

data from over 900 existing vertical wells with Meramec and Osage penetrations previously drilled on or around our acreage;

•

core samples and cuttings across each of the five identified benches;

•

approximately 900 miles of 2D seismic data and over 300 square miles of 3D seismic data covering a portion of our acreage; and

•

borehole imaging, density, porosity, resistivity and mud logs across our acreage.

Since spudding our first well in the NW Stack in March 2015, we have primarily focused our drilling program on further delineating and de-risking our acreage across the full extent of our NW Stack position. We believe we have successfully delineated each of the five benches that we have identified within the Meramec and Osage intervals. We achieved this by:

•

drilling and completing 33 Tapstone-operated horizontal wells across our position in each of the five identified benches; and

•

analyzing over 50 horizontal wells drilled by offset operators on or around our acreage.

acreage” or acreage that we “operate” in this prospectus. As of December 31, 2016 we operated 78% of our net acreage in the NW Stack and had an average working interest of 72% in the 336 sections that we operated. For the three months ended December 31, 2016, our net production in the NW Stack was 5.1 MBoe/d, of which 14% was oil, 18% was NGLs and 68% was natural gas. Of the 33 Tapstone-operated horizontal wells we have drilled and completed in the NW Stack as of March 23, 2017, three wells were in the Upper Meramec, four wells were in the Middle Meramec, seven wells were in the Lower Meramec, twelve wells were in the Upper Osage and seven wells were in the Lower Osage. Additionally, as of March 23, 2017, two Tapstone-operated horizontal wells were waiting on completion (one in the Lower Meramec and one in the Upper Osage) and four Tapstone-operated horizontal wells were in the process of being drilled (two in the Upper Meramec and two in the Lower Meramec).

The following map indicates the location of our operated horizontal wells that we have drilled and completed and the location of the wells we are drilling in the NW Stack as of March 23, 2017.

LOGO

The following table presents data on the operated horizontal wells that we have drilled or are in the process of drilling in the NW Stack as of March 23, 2017. See “Business—Oil and Natural Gas Production Prices and Costs—Drilling Results”.


Well Name	Target Bench	First Production	Peak 30 IP (Boe/d) (1)(2)		Peak 30 IP (% Liquids) (1)(2)			Days to Drill		Total D&C ($MM) (3)
1. DENNIS 28-19-16 1H	Lower Osage	6/9/2015		1,911		35	%		71	$	7.0
2. BOZARTH 33-19-16 1H	Middle Meramec	8/25/2015		1,050		45	%		69	$	7.6
3. SHAW TRUST 30-22-19 1H	Middle Meramec	9/15/2015		631		67	%		38	$	5.8
4. WILSON 35-19-16 1H	Lower Osage	10/6/2015		1,328		44	%		46	$	5.3
5. BRANSTETTER 2-19-18 1H	Lower Meramec	11/26/2015		1,387		60	%		61	$	6.9
6. SEIFRIED TRUST 4-18-16 1H	Lower Osage	12/14/2015		1,473		30	%		69	$	6.8
7. HOWARD 5-19-17 1H	Upper Osage	1/9/2016		3,248		70	%		51	$	6.6
8. CARTER 29-19-17 1H	Lower Meramec	2/4/2016		1,790		43	%		44	$	5.0
9. IRVING 19-19-16 1H	Lower Osage	2/16/2016		971		45	%		50	$	5.4
10. WHITE 8-20-19 1H	Upper Osage	3/31/2016		1,359		39	%		51	$	5.0
11. YOUNG 6-20-18 1H	Middle Meramec	4/6/2016		475		15	%		45	$	5.4
12. RANDY 9-18-16 1H	Lower Osage	4/13/2016		1,381		33	%		59	$	5.6
13. CARA 28-20-18 1H	Lower Meramec	5/27/2016		584		48	%		52	$	5.4
14. RANDALL 15-20-20 1H	Upper Osage	6/3/2016		1,851		52	%		49	$	5.1
15. SEIDEL 5-19-18 1H	Lower Meramec	6/27/2016		675		36	%		48	$	5.0
16. SALISBURY 27-19-20 1H	Lower Osage	7/12/2016		1,111		21	%		48	$	5.4
17. AMPARAN 6-20-22 1H (4)	Lower Meramec	8/10/2016		515		7	%		42	$	5.0
18. DRINNON 32-18-17 1H	Upper Osage	9/6/2016		621		7	%		61	$	6.9
19. SPORTSMAN 3-18-16 1H	Lower Meramec	9/20/2016		1,375		44	%		44	$	4.4
20. MCCORMICK 3-19-20 1H	Upper Osage	10/2/2016		988		27	%		53	$	6.0
21. STORY 23-21-20 1H	Upper Osage	10/3/2016		855		44	%		54	$	5.1
22. LINDA 19-20-19 1H	Upper Osage	11/8/2016		1,202		38	%		50	$	5.0
23. MCALARY 25-19-20 1H	Lower Osage	11/22/2016		806		26	%		72	$	7.0
24. RUSSELL 17-19-17 1H	Upper Meramec	11/23/2016		1,125		62	%		41	$	6.0
25. KROWS 19-19-17 1H	Lower Meramec	12/14/2016		1,399		46	%		41	$	5.8
26. MAIN 3-19-19 1H	Upper Osage	1/17/2017		382		29	%		71	$	7.7
27. MERLE 32-19-17 1H	Upper Meramec	1/31/2017		746		53	%		28	$	4.7
28. CRITES 13-20-20 1H	Upper Osage	2/1/2017		1,261		50	%		45	$	5.8
29. MARILYN 14-20-20 1H	Upper Osage	2/23/2017							38	$	4.8
30. FRED 4-19-17 1H	Upper Osage	3/6/2017							52
31. BRUCE 16-20-20 1H	Middle Meramec	3/13/2017							42
32. RAPP 1-19-18 1H	Upper Meramec	3/23/2017							42
33. HEDGES 6-19-17 1H	Upper Osage	(5)							48
34. EARL 30-19-17 1H	Lower Meramec	(6)							29
35. SEAL TRUST 29-19-16 1H	Upper Osage	(6)							23
36. BROWN TRUST 31-20-17 1H	Upper Meramec	(7)
37. ELAINE 12/13-19-18 1H	Upper Meramec - 2 Mile	(7)
38. AMANDA 13-19-17 1H	Lower Meramec	(7)
39. ROY 26-19-18 1H	Lower Meramec	(7)

(1)	The peak initial production data is determined by selecting the maximum 30-day rolling averages for days that had recorded production.

(2)	Shown on a combined basis for oil, natural gas and NGLs.

(3)	Cost data reflects field estimates for wells 26 through 29. Certain high-cost wells reflect certain additional costs related to data acquisition methods such as drilling pilot holes and taking core samples, and in some cases, significant mechanical issues.

(4)	Plugged prior to December 31, 2016 due to a tool being lost in the well.

(5)	Well is in flowback.

(6)	Wells are waiting on completion.

(7)	Wells are being drilled.

We are focused on optimizing our operational practices in order to enhance recoveries, reduce costs and increase single-well rates of return. Our initial drilling program in the NW Stack focused on delineation, and our well design and completion practices utilized consistent methods with limited variability in order to obtain a better understanding of the reservoir potential across our acreage position. These practices included: (i) well location selection designed to test the geographic expanse of our acreage, (ii) consistent, low intensity completion designs and (iii) single-mile lateral lengths for our operated horizontal wells. Our wellbore targeting to date has also lacked the benefit of 3D seismic data. Now that we have successfully delineated the position and have obtained 3D seismic data over a portion of our acreage, we are adjusting our focus to optimize our operational practices by:

•

focusing our wellbore targeting with the assistance of 3D seismic data;

•

improving drilling efficiencies;

•

utilizing advanced completion techniques;

•

increasing lateral lengths from one-mile to two-mile laterals; and

•

maximizing efficiencies in field development.

As of March 23, 2017, we operated four rigs in the NW Stack and intend to bring our total operated rig count to six operated rigs by the end of 2017. We expect that, at this development pace, we will be capable of drilling approximately 39 gross wells in 2017. At this assumed development pace and with over 2,700 gross operated identified horizontal drilling locations, we estimate that we have a multi-decade inventory of development locations in the NW Stack.

Legacy Producing Properties

Our legacy producing properties in the Anadarko Basin are in the following areas: the Stiles Ranch Field located in Wheeler County, Texas in the Granite Wash play (“Stiles Ranch”); the Verden Field located in Caddo and Grady Counties, Oklahoma (“Verden”); the Mississippian formation in Barber, Harper and Reno Counties, Kansas (“Kansas”); and the Mocane-Laverne Field in Beaver, Harper and Ellis Counties, Oklahoma (“Mocane-Laverne”). For the three months ended December 31, 2016, the average net production from these legacy producing properties was 18.2 MBoe/d, of which 15% was oil, 57% was natural gas and 28% was NGLs. We believe economic development potential exists in our legacy producing properties, as these properties are located in areas that are being actively developed by industry peers with successful results.

All of our acreage holdings outside of the NW Stack and Kansas are held by production, which offers us optionality to develop the properties opportunistically in the future. In addition, these legacy producing properties provide an important source of cash flows to fund a portion of our development drilling activities in the NW Stack and are generally characterized as having long-lived, predictable production profiles. As of December 31, 2016, we owned approximately 9,080 net acres in Stiles Ranch that were all held by production from 223 operated and 10 non-operated gross wells. As of December 31, 2016, our acreage position in Verden consisted of approximately 15,795 net acres that were all held by production from 117 operated and 52 non-operated gross wells. As of December 31, 2016, our acreage position in Kansas consisted of approximately 112,435 net acres, approximately 39,000 of which were held by production from 78 operated gross wells. As of December 31, 2016, our acreage position in Mocane-Laverne consisted of approximately 87,260 net acres that were all held by production from 312 operated and 130 non-operated gross wells.

Proved Reserves

The following table provides summary information regarding our proved reserves as of December 31, 2016 and our production for the three months ended December 31, 2016. The reserve estimates attributable to our assets as of December 31, 2016 are based on a reserve report prepared by Ryder Scott, independent petroleum engineers, in accordance with the SEC’s rule regarding reserve reporting currently in effect.


	Estimated Total Proved Reserves as of December 31, 2016 (SEC Pricing) (1)							Net Production for the Three Months Ended December 31, 2016 (MBoe/d)
Project Area	Oil (MMBbls)	NGLs (MMBbls)	Natural Gas (Bcf)	Total (MMBoe)	% Oil	% NGLs	% Natural Gas
NW Stack	4.5	5.5	107.8	28.0	16%	20%	64%	5.1
Stiles Ranch	4.6	15.2	123.2	40.3	11%	38%	51%	10.3
Verden	0.5	0.1	63.3	11.1	4%	1%	95%	2.1
Kansas	8.1	5.0	72.1	25.2	32%	20%	48%	4.1
Mocane-Laverne	0.4	1.3	19.9	5.0	8%	26%	66%	1.7

Total (2)	18.0	27.1	386.2	109.5	16%	25%	59%	23.3

(1)

Our estimated total proved reserves were determined using average first-day-of-the-month prices for the prior twelve months in accordance with SEC guidance. For oil and NGLs volumes, the average WTI posted price of $42.75 per barrel as of December 31, 2016, was adjusted for gravity, quality, local conditions, gathering, transportation fees and distance from market. For natural gas volumes, the average Henry Hub spot price of $2.49 per MMBtu as of December 31, 2016, was similarly adjusted for gravity, quality, local conditions, gathering, transportation fees and distance from market. All prices are held constant throughout the lives of the properties. The average adjusted product prices weighted by production over the remaining lives of the properties were $41.85 per barrel of oil, $14.94 per barrel of NGLs and $2.35 per Mcf of natural gas as of December 31, 2016.

(2)	Totals may not sum or recalculate due to rounding.

Drilling Inventory

We have received 3D seismic data that we purchased from Devon Energy Corporation (“Devon”) covering a 329 square mile area that includes approximately 33,177 net acres in our position in the NW Stack (the “Seiling 3D”). We also have the option and plan to purchase portions of additional 3D seismic data currently being shot by Devon that covers an area of over 700 square miles that includes 80,860 net acres in our position in the NW Stack (the “Moscow Flats 3D”). We expect to begin receiving the preliminary Moscow Flats 3D seismic data in the second half of 2017. We intend to focus our 2017 drilling program on our identified horizontal drilling locations located within the area covered by the Seiling 3D.

Our estimated drilling inventory in the NW Stack is based on drilling ten wells per section across the five identified benches in the Meramec and Osage intervals. The ten wells per section assumes a minimum lateral spacing equivalent to four wells per section in the Upper Meramec, with the remaining wells allocated across the four deeper benches. Additionally, we have adjusted our identified horizontal drilling locations in the NW Stack to account for certain identifiable geologic hazards. Using the Seiling 3D seismic data, we identified and removed locations from our drilling inventory that could potentially be negatively impacted by such geologic hazards. On an unadjusted basis, this equated to approximately 16.5% of the operated identified horizontal drilling locations within the Seiling 3D seismic outline. To account for geologic hazards in our acreage outside of the Seiling 3D seismic outline, the same percentage reduction was applied to our gross identified horizontal drilling locations without current 3D seismic coverage.

In this prospectus, our “identified horizontal drilling locations” in the NW Stack refer to identified horizontal drilling locations that have been adjusted using the above methodology and are presented on a single-mile lateral basis. As of December 31, 2016, we had a drilling inventory consisting of 5,849 gross (2,546 net) identified horizontal drilling locations in the NW Stack. Of such inventory, 558 gross (422 net) operated identified horizontal drilling locations are captured within the Seiling 3D seismic outline and 1,472 gross (1,050

net) operated identified horizontal drilling locations are within the outline of the Moscow Flats 3D seismic shoot that is currently underway. The remaining 748 gross (519 net) operated identified horizontal drilling locations are outside of any current or planned 3D seismic shoots.

In the NW Stack, we bifurcate our identified horizontal drilling locations between oil and natural gas condensate windows based on subsea total vertical depth (“TVD”). Locations with a subsea TVD greater than 9,150 feet generally exhibit properties consistent with natural gas condensate wells and are classified as such. Locations with a subsea TVD of less than 9,150 feet are classified as oil locations. As of December 31, 2016, we had 1,493 gross (1,084 net) and 1,285 gross (906 net) operated identified horizontal drilling locations in the oil window and natural gas condensate window, respectively.

To date, our horizontal drilling program has been focused primarily on the Meramec and Osage intervals in the NW Stack. The table below sets forth a summary of our identified horizontal drilling locations in the NW Stack as of December 31, 2016. Additionally, our legacy producing properties contain 488 gross (366 net) horizontal drilling locations, of which we operated 457 gross (364 net) locations and 71 gross (67 net) locations were associated with proved undeveloped reserves as of December 31, 2016.


	NW Stack Horizontal Drilling Locations(1)(2)(3)(4)(5)																	Operated Inventory Life (6)
	Net Acres		Average Working Interest			Gross Locations						Net Locations
	Net Acres		Average Working Interest			Oil		Gas Condensate		Total		Oil		Gas Condensate		Total
Operated – Seiling 3D		33,177		76	%		341		217		558		265		157		422		11
Operated – Moscow Flats 3D		80,860		71	%		1,008		464		1,472		714		335		1,050		28
Operated – Outside 3D		39,935		69	%		144		604		748		105		414		519		14

Total Operated		153,972		72	%		1,493		1,285		2,778		1,084		906		1,990		53
Non-Operated		42,733		18	%		1,608		1,463		3,071		283		273		556

Total NW Stack		196,705		44	%		3,101		2,748		5,849		1,367		1,179		2,546

(1)

We have estimated our drilling locations based on well spacing assumptions and upon the evaluation of our horizontal drilling results and those of other operators in our area, combined with our interpretation of available geologic and engineering data. Please read “Business—Our Properties” for more information regarding the process and criteria through which these drilling locations were identified.

(2)

The drilling locations that we actually drill will depend on the availability of capital, regulatory approvals, commodity prices, costs, actual drilling results and other factors. Any drilling activities we are able to conduct on these identified locations may not be successful and may not result in additional proved reserves. Further, to the extent the drilling locations are associated with leased acreage with expiration terms, we may lose the right to develop the related locations if a well is not commenced before the end of the primary lease term. Please read “Risk Factors—Risks Related to Our Business—Our identified drilling locations are scheduled out 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 generate sufficient cash from operations or obtain required capital or financing on satisfactory terms that would be necessary to drill such locations”.

(3)	Our total identified horizontal drilling locations include 48 gross (26 net) locations associated with proved undeveloped reserves as of December 31, 2016 in the NW Stack.

(4)	Includes locations targeting the Upper Meramec, Middle Meramec, Lower Meramec, Upper Osage and Lower Osage benches. Please read “Business—Our Properties—NW Stack” for a description of these benches.

(5)	Totals may not sum or recalculate due to rounding.

(6)

We have estimated inventory life years for our operated locations based on total gross locations and our 2017 development plan to drill 39 gross horizontal wells (approximately 26 of which we anticipate to be single-mile laterals and 13 of which we anticipate to be two-mile laterals, which equates to 52 single-mile equivalent wells).

Transportation and Marketing

Our acreage has access to numerous end markets for oil, natural gas and NGLs, which provides us significant takeaway optionality as well as a regional price advantage. Our acreage is strategically located near well-developed infrastructure with access to almost every major consuming market including markets in the Upper Midwest through the Chicago City Gate and markets to the east of the Mississippi River through the Perryville Hub in Perryville, Louisiana. Both hubs offer optionality in selling natural gas at low basis differentials and provide us with a competitive advantage when compared to other plays in the lower 48 states. Proximity and direct access to the Gulf Coast also allows us to benefit from future LNG exports, petrochemical industry development and potential exports of natural gas to Mexico, as well as any future regional and local demand growth.

A substantial portion of our natural gas production in Stiles Ranch, Verden and the NW Stack is dedicated to Enable Midstream Partners, LP (“Enable”). The majority of natural gas production in each of Verden and Stiles Ranch is dedicated to, gathered and processed by Enable under 15-year gas gathering and processing agreements that commenced in July 2011 and January 2013, respectively. In December 2015, we signed a 15-year gas gathering, processing, and purchase agreement with Enable under which we have dedicated the majority of our NW Stack acreage. The competitive pricing levels under the December 2015 agreement with Enable with no minimum volume commitment allow us to control our pace of development in the NW Stack and eliminate risks associated with transportation and marketing. Plains Marketing, L.P. (“Plains Marketing”) currently purchases all of our oil production, the majority of which is dedicated and purchased under a five-year agreement that commenced in April 2015. Our commitment to Plains Marketing requires us to deliver 4,000 Bbl/d on a gross annual basis from April 1st to March 31st. In March 2017, we delivered over 4,000 Bbl/d. Please read “Business—Operations—Transportation and Marketing” for a description of these agreements.

Owned Infrastructure

In Stiles Ranch, we own and operate a fee-based midstream system consisting of low pressure natural gas gathering pipeline, intermediate/high pressure natural gas gathering pipeline, gas lift pipeline and crude and NGLs gathering pipeline and compression and storage for oil, water and NGLs located in Wheeler County, Texas (“Wheeler Midstream”). We believe our ownership of this midstream infrastructure allows us to reduce our costs in Stiles Ranch, promote overall efficiency of operations and increase our rates of return. Wheeler Midstream is an integrated pipeline gathering system that utilizes centralized compression, stabilization and tankage to support multi-pad drilling in 14 sections across the area. The gathering assets include 60 miles of low pressure gas gathering pipeline, 26 miles of intermediate/high pressure gas gathering pipeline, 24 miles of gas lift pipeline and 23 miles of crude and NGLs gathering pipeline. With respect to storage at Wheeler Midstream, we have 12 MBbls/d of oil gathering capacity and 22 MBbls of oil storage capacity, 30 MBbls/d of water gathering capacity and 30 MBbls of water storage capacity and 2 MBbls of NGLs storage capacity. Wheeler Midstream has four gas driven compressor stations with an aggregate of 28,890 horsepower. We rely exclusively on third-party service providers to gather our oil and natural gas production in the NW Stack, Verden, Kansas and Mocane-Laverne.

Capital Budget

two-mile laterals. Approximately 56% of our planned wells in 2017 will be targeting the oil window, with the remaining wells targeting the natural gas condensate window. Of the 39 gross horizontal wells we expect to drill, we expect to bring 29 wells to first sales during 2017. We intend to use the remaining $52 million of our 2017 capital budget for the purchase of 3D seismic data, leasing activities in the NW Stack, workover and additional capitalized items. Our 2017 capital budget excludes any amounts that may be paid for acquisitions.

For the years ended December 31, 2016 and 2015, our aggregate drilling, completion and leaseholds capital expenditures were $185.1 million and $180.3 million, respectively, excluding acquisitions.

Because we operate a high percentage of our acreage, the amount and timing of these capital expenditures is largely discretionary and within our control. We retain the flexibility to defer a portion of these planned capital expenditures depending on a variety of factors, including but not limited to, the success of our drilling activities, prevailing and anticipated prices for oil, natural gas and NGLs, the availability of necessary equipment, infrastructure and capital, the receipt and timing of required regulatory permits and approvals, seasonal conditions, drilling and acquisition costs and the level of participation by other interest owners.

Business Strategies

Our primary objective is to maximize stockholder value across business cycles by pursuing the following strategies:

•

Economically grow production, reserves and cash flow by developing our extensive drilling inventory. The majority of our development opportunities are concentrated in our contiguous, approximately 200,000 net acre position in the NW Stack. As of December 31, 2016, we had assembled over 2,700 gross operated identified horizontal drilling locations across the oil and natural gas condensate windows of the NW Stack, providing us with a multi-decade development inventory at our current pace of activity. Based on our extensive technical evaluation, including 33 Tapstone-operated horizontal wells, over 50 horizontal wells drilled by offset operators, over 900 existing vertical wells drilled on or around our acreage and 2D and 3D seismic data available in the area, as well as other technical information we have accumulated regarding our NW Stack acreage, we believe our acreage position in the NW Stack is substantially delineated across the Meramec and Osage intervals. Given the initial success of our drilling program, the established consistency of our geologic model, the extensive catalog of technical information and the industry activity around our acreage, we believe our acreage position in the NW Stack provides us with a significant inventory of development locations expected to offer attractive single-well rates of return.

•

Focus on advanced operational, drilling and completion techniques that are expected to result in improved capital efficiencies and increased well returns. As we accelerate the development of our NW Stack acreage position, our management and technical teams will focus on utilizing advanced operational, drilling and completion techniques, in conjunction with 3D seismic data, to maximize hydrocarbon recovery per well. While maximizing per-well recovery, we expect to minimize our capital and operating costs per Boe, with the ultimate objective of maximizing returns of our large drilling inventory. In order to achieve these objectives, we intend to:

•

maximize well production and hydrocarbon recovery through advanced drilling, completion and production methods such as optimizing wellbore targeting, lateral lengths and completion design; and

•

minimize the capital costs per Boe of drilling and completing horizontal wells through knowledge of the target formations, optimization of drilling techniques to reduce cycle times and engagement in best cost management practices.

Our highly experienced management and technical teams have a substantial track record of developing unconventional plays similar to the NW Stack and will be instrumental in realizing our targeted operational efficiencies.

•

Take advantage of our balanced acreage position, spanning the oil and natural gas condensate windows of the NW Stack, providing us optionality around our drilling plan, capital program and commodity mix. Our contiguous acreage position spans a highly productive area across the over-pressured oil and natural gas condensate windows of the NW Stack. We believe our balanced mix of oil and natural gas condensate locations provides us with the flexibility to adjust our drilling program and capital expenditure plans in response to the commodity price environment. The natural gas condensate we produce has a high Btu content that typically ranges from 1,100 to 1,300 Btu per standard cubic foot, further enhancing economics of our production as compared to dry natural gas. We believe this diversity of commodity exposure and our ability to modify the development plan and the associated capital expenditures help mitigate commodity price exposure.

•

Maintain a high degree of operational control over our contiguous acreage position. We were among the first operators to identify the resource potential of the NW Stack and have pursued a focused leasing program there beginning in September 2014. The success of our leasing program and our early entry into the play have uniquely positioned us to hold a high average working interest in wells that we operate. As of December 31, 2016, we operated 78% of our net acreage in the NW Stack and had an average working interest of 72% across the 336 sections we operated. We believe that by retaining operational control over our acreage position we will be able to efficiently manage the timing and amount of our capital expenditures and operating costs, thus optimizing our drilling strategies and completion methods. Additionally, our operational control will allow us to drill longer laterals, which we believe will generate higher EURs and greater rates of return per well.

•

Maintain a disciplined financial strategy while pursuing growth in the NW Stack. We intend to maintain a disciplined financial profile that will provide us flexibility across various commodity and capital market cycles. Furthermore, we intend to fund the development of our NW Stack acreage position with cash flow from our legacy producing properties, availability under our credit facility and capital markets offerings when appropriate, while prudently managing our capital structure, leverage and liquidity. We expect to maintain an active commodity hedging program with the intent of reducing our exposure to commodity price volatility thereby enabling us to protect our cash flows and returns and maintain liquidity to fund our capital program and investment opportunities.

Our Competitive Strengths

We believe the following strengths will allow us to successfully execute on our business strategies:

•

Extensive, contiguous and operated acreage position concentrated in the NW Stack that is expected to generate attractive single-well rates of return. As of December 31, 2016, we operated 78% of our approximately 200,000 net acres in the NW Stack, which we believe to be emerging as one of North America’s most prolific, oil and natural gas condensate plays. As evidenced by initial production rates and estimated EURs per well on our Tapstone-operated horizontal wells, we believe the returns from our wells in the NW Stack are competitive with returns generated among other leading plays across the lower 48 states. We operate the majority of our position within the NW Stack, which provides us with control and flexibility to adjust the pace of our development program, as well as the length of our laterals and our drilling and completion techniques, in order to optimize our capital investments.

•

Our acreage position in the NW Stack has been substantially delineated across multiple productive benches in which we have identified a multi-decade balanced inventory of drilling

locations. We have substantially delineated our NW Stack acreage through extensive technical evaluation, including 33 Tapstone-operated horizontal wells, over 50 horizontal wells drilled by offset operators, over 900 existing vertical wells drilled on or around our acreage and 2D and 3D seismic data available in the area. As of December 31, 2016, we had identified over 2,700 gross operated horizontal drilling locations in the NW Stack, providing us with a multi-decade drilling inventory. Our drilling activity has been and will continue to be focused on the oil and natural gas condensate windows of the NW Stack, which is expected to produce attractive single-well economics. Additionally, as we accelerate the development of our acreage position, we are optimizing our development plan in order to maximize the value of our resource potential. As of March 23, 2017, we operated four rigs deployed across our acreage position and intend to increase our rig count to a total of six operated rigs by the end of 2017.

•

Significant operational control in the NW Stack with attractive development opportunities. As of December 31, 2016, we operated 78% of our net acreage in the NW Stack and had an average working interest of 72% in the 336 sections that we operated. We intend to maintain operational control over a majority of our drilling inventory, which we believe will enable us to increase our production and reserves while lowering our development costs. Our control over operations also allows us to utilize cost-effective operating practices, including the selection of drilling locations, timing of development and associated capital expenditures and continuous improvement of drilling, completion and stimulation techniques. In addition, operational control allows us to adjust our development plan to target the most economic locations depending on the then existing commodity price environment. Further, we believe our ability to control costs will allow us to continue to enhance our margins, driven by competitive realized pricing and low-cost development.

•

Existing legacy producing properties generate predictable production and cash flow to fund our NW Stack drilling program. In addition to our position in the NW Stack, we also own interests throughout the Anadarko Basin in Stiles Ranch, Verden, Kansas and Mocane-Laverne, which we refer to as our legacy producing properties. Substantially all of our acreage outside of the NW Stack and Kansas is held by production, allowing us optionality on the pace of development. These assets are generally characterized by long-lived reserves, with predictable production profiles. Our net production from these assets has generated valuable cash flow that we have reinvested in our business and plan to continue to reinvest in our business, primarily in the development of the NW Stack, thus reducing our reliance on externally sourced capital. Based on the continued development of these areas by offset operators, we believe we have additional development opportunities in our legacy producing properties with the potential to provide attractive rates of return.

•

Acreage position that is not burdened by onerous takeaway commitments in a geographic location that maximizes realized commodity pricing. Our acreage position offers us optionality and access to numerous end markets for oil, natural gas and NGLs and provides us with a regional price advantage. Our acreage is strategically located near well-developed infrastructure with access to almost every major consuming market, including markets in the Upper Midwest through the Chicago City Gate and markets to the east of the Mississippi River through the Perryville Hub in Perryville, Louisiana. Both hubs offer optionality in selling natural gas at low basis differentials and provide us with a competitive advantage when compared to other plays actively being developed in the lower 48 states. Proximity and direct access to the Gulf Coast also allows us to benefit from future LNG exports, petrochemical industry development and potential exports of natural gas to Mexico, as well as any future regional and local demand growth. Dedication of a substantial portion of our natural gas production in the NW Stack to Enable at competitive pricing levels and no minimum volume commitment allows us to control our pace of development in the NW Stack and eliminate risks associated with the transportation and marketing of our gas production in the NW

Stack. Our commitment to Plains Marketing requires us to deliver 4,000 Bbl/d pursuant to a five- year agreement that commenced in April 2015. In March 2017, we delivered over 4,000 Bbl/d.

•

High caliber management and technical teams with deep operating experience and a proven track record. Our management and technical teams have extensive experience and a history of working together on cost-efficient, large scale drilling programs in the Anadarko Basin. Our management and technical teams have collectively participated in the drilling of over 10,000 horizontal wells across multiple unconventional plays in the lower 48 states, were responsible for operating as many as 177 rigs at a given time, and have a successful track record of reserve and production growth. In particular, these teams have been instrumental in driving early stage identification, exploration and, then, accelerated development of unconventional plays similar to the NW Stack by (i) optimizing wellbore targeting based on 3D seismic data, (ii) drilling extended length laterals, (iii) reducing cycle times, (iv) utilizing advanced completion techniques and (v) maximizing efficiencies in field development. Members of our management team have previously held positions with major independent oil and natural gas companies, including Continental Resources, Inc., Chesapeake Energy Corporation and SandRidge Energy, Inc.

•

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. After giving effect to this offering and the use of the proceeds, including repayment of our credit facility, we will have approximately $ million of liquidity, with $ million of cash and cash equivalents and $ million of available borrowing capacity under our credit facility. We believe this borrowing capacity, along with our cash flow from operations and existing cash on the balance sheet, will provide us with sufficient liquidity to execute on our capital program. Subject to changes in commodity prices, we would expect the available borrowing capacity to increase as we convert proved undeveloped reserves to proved producing reserves, which may provide us additional flexibility in the future.

Recent Developments

Amendment to Credit Facility

On March 31, 2017, we entered into an amendment to our credit facility, which maintains the $385 million borrowing base under the credit facility, and provides that the lenders will redetermine the borrowing base if we have not applied at least $250 million in net proceeds from this offering to prepay loans outstanding under the credit facility on or prior to May 15, 2017. If such redetermination of the borrowing base occurs, we would not expect such redetermination to be effective sooner than July 2017. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Our Credit Facility”.

Corporate Reorganization

We were incorporated under the laws of the State of Delaware in December 2016 to become a holding company for Tapstone Energy, LLC and its assets and operations. Tapstone Energy, LLC, which is our accounting predecessor, was formed as a Delaware limited liability company in December 2013. Certain Management Members hold incentive units in Tapstone Energy, LLC that entitle such Management Members to a portion of any proceeds distributed by Tapstone Energy, LLC following the achievement of certain return thresholds by the capital interest owners of Tapstone Energy, LLC.

Pursuant to the terms of certain reorganization transactions that will be completed immediately prior to the closing of this offering, Tapstone Energy, LLC will merge into a subsidiary of Tapstone Energy Inc., with the Existing Owners, including the holders of incentive units, receiving shares of our common stock, with the allocation of such shares among the Existing Owners to be determined pursuant to the terms of the limited liability company agreement of Tapstone Energy, LLC by reference to the volume weighted average price of the

publicly traded shares of our common stock during the initial 20 days during which our common stock is traded on the NYSE. As a result of these transactions, Tapstone Energy, LLC will become a wholly-owned subsidiary of Tapstone Energy Inc. Please read “Corporate Reorganization”.

The following diagram illustrates our simplified ownership structure after giving effect to our corporate reorganization and this offering (assuming that the underwriters’ option to purchase additional shares is not exercised).

LOGO

(1)	Includes GSO and the Management Members.

For more information, please read “Corporate Reorganization”.

Our Principal Stockholder

GSO is the global credit investment platform of Blackstone. With approximately $93 billion of assets under management as of December 31, 2016, GSO is one of the largest alternative asset managers in the world focused on the leveraged finance marketplace. GSO has a strong track record of investing in the energy sector since its inception in 2005, and it currently manages or sub-advises over $10 billion of assets in the energy sector. GSO is a major provider of credit for small and middle market companies and has substantial upstream E&P holdings in most major North American oil and natural gas basins. Upon completion of this offering, GSO will own approximately % of our common stock (or % if the underwriters exercise in full their option to purchase additional shares).

Risk Factors

Investing in our common stock involves risks that include the speculative nature of oil and natural gas development and production, competition, volatile oil, natural gas and NGLs prices and other material factors. You should read carefully the section of this prospectus entitled “Risk Factors” for an explanation of these risks before investing in our common stock. In particular, the following considerations may offset our competitive strengths or have a negative effect on our strategy or operating activities, which could cause a decrease in the price of our common stock and a loss of all or part of your investment:

•

Oil, natural gas and NGLs prices are volatile and have seen significant declines in recent years. A further reduction or sustained decline in oil, natural gas and NGLs prices could adversely affect our business, financial condition and results of operations and our ability to meet our capital expenditure obligations and financial commitments.

•

Our development plan and acquisitions require substantial capital expenditures. We may be unable to generate sufficient cash from operations or obtain required capital or financing on satisfactory terms, which could lead to a decline in our ability to access or grow production and reserves.

•

Part of our strategy involves using some of the latest available horizontal drilling and completion techniques, which involve risks and uncertainties in their application.

•

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 identified drilling locations are scheduled out 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 generate sufficient cash from operations or obtain required capital or financing on satisfactory terms that would be necessary to drill such locations.

•

Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

•

Unless we replace our reserves with new reserves and develop those reserves, our reserves and production will decline, which would adversely affect our future cash flows and results of operations.

•

We may not be able to generate sufficient cash to service all of our indebtedness and may be forced to take other actions to satisfy our obligations under applicable debt instruments, which may not be successful.

•

Any significant reduction in our borrowing base under our credit facility as a result of the periodic borrowing base redeterminations or otherwise may negatively impact our ability to fund our operations.

•

Certain of our undeveloped leasehold acreage is subject to leases that will expire over the next several years unless production is established on units containing the acreage, we pay the lessees option payments to extend the leases for an additional two years or the leases are renewed.

•

We will not be the operator on all of our acreage or drilling locations, and, therefore, we will not be able to control the timing of exploration or development efforts, associated costs, or the rate of production of any non-operated assets.

•

The marketability of our production and our price realizations are dependent upon the availability of transportation and other facilities, many of which we do not control. If these facilities are unavailable, our operations could be interrupted and our revenues reduced.

•

The development of our estimated PUDs may take longer and may require higher levels of capital expenditures than we currently anticipate. Therefore, our estimated PUDs may not be ultimately developed or produced.

•

Our method of accounting for investments in oil and natural gas properties may result in ceiling test write-downs, which could negatively impact our results of operations.

•

We depend upon several significant purchasers for the sale of most of our oil, natural gas and NGLs production.

•

Our operations may be exposed to significant delays, costs and liabilities as a result of environmental and occupational health and safety requirements applicable to our business activities.

•

We may incur substantial losses and be subject to substantial liability claims as a result of our operations. Additionally, we may not be insured for, or our insurance may be inadequate to protect us against, these risks.

•

The unavailability or high cost of additional drilling rigs, equipment, supplies, personnel and oilfield services could adversely affect our ability to execute our development plans within our budget and on a timely basis.

•

We could experience periods of higher costs if commodity prices rise. These increases could reduce our profitability, cash flow and ability to complete development activities as planned.

•

Climate change laws and regulations restricting emissions of greenhouse gases (“GHGs”) could result in increased operating costs and reduced demand for the oil and natural gas that we produce, while potential physical effects of climate change could disrupt our production and cause us to incur significant costs in preparing for or responding to those effects.

•

Federal, state and local legislative and regulatory initiatives relating to hydraulic fracturing as well as governmental reviews of such activities could result in increased costs and additional operating restrictions or delays in the completion of oil and natural gas wells and adversely affect our production.

•

The requirements of being a public company, including compliance with the reporting requirements of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), and the requirements of the Sarbanes-Oxley Act of 2002 (“Sarbanes-Oxley”), may strain our resources, increase our costs and distract management, and we may be unable to comply with these requirements in a timely or cost-effective manner.

•

GSO will have the ability to direct the voting of a majority of our common stock, and its interests may conflict with those of our other stockholders.

•

We expect to be a “controlled company” within the meaning of the New York Stock Exchange (the “NYSE”) rules and, as a result, will qualify for and intend to rely on exemptions from certain corporate governance requirements.

Emerging Growth Company

We are an “emerging growth company” as such term is used in the Jumpstart Our Business Startups Act of 2012 (the “JOBS Act”). For as long as we are an emerging growth company, unlike public companies that are not emerging growth companies under the JOBS Act, we will not be required to:

•

provide an auditor’s attestation report on the effectiveness of our system of internal control over financial reporting pursuant to Section 404(b) of Sarbanes-Oxley;

•

provide more than two years of audited financial statements and related management’s discussion and analysis of financial condition and results of operations;

•

comply with any new requirements adopted by the Public Company Accounting Oversight Board (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;

•

provide certain disclosure regarding executive compensation required of larger public companies or hold stockholder advisory votes on executive compensation required by the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”); or

•

obtain stockholder approval of any golden parachute payments not previously approved.

We will cease to be an emerging growth company upon the earliest of:

•

the last day of the fiscal year in which we have $1.0 billion or more in annual revenues;

•

the date on which we become a “large accelerated filer” (the fiscal year-end on which the total market value of our common equity securities held by non-affiliates is $700 million or more as of June 30);

•

the date on which we issue more than $1.0 billion of non-convertible debt over a three-year period; or

•

the last day of the fiscal year following the fifth anniversary of our initial public offering.

In addition, Section 107 of the JOBS Act provides that an emerging growth company can take advantage of the extended transition period provided in Section 7(a)(2)(B) of the Securities Act of 1933, as amended (the “Securities Act”), for complying with new or revised accounting standards, but we hereby irrevocably opt out of the extended transition period and, as a result, we will adopt new or revised accounting standards on the relevant dates in which adoption of such standards is required for other public companies.

Principal Executive Offices and Internet Address

Our principal executive offices are located at 100 East Main Street, Oklahoma City, Oklahoma 73104, and our telephone number at that address is (405) 702-1600.

Our website address is www.tapstoneenergy.com. We expect to make our periodic reports and other information filed with or furnished to the SEC available free of charge through our website as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. Information on our website or any other website is not incorporated by reference into, and does not constitute a part of, this prospectus.

The Offering

Issuer

Tapstone Energy Inc.

Common stock offered by us

shares.

Common stock outstanding after this offering

shares.

Option to purchase additional shares

The selling stockholder has granted the underwriters a 30-day option to purchase up to an aggregate of additional shares of our common stock to the extent the underwriters sell more than shares of common stock in this offering. If the underwriters exercise their option to purchase additional shares of common stock from the selling stockholder, we will not receive any proceeds from the sale of such shares.

Use of proceeds

We expect to receive approximately $ million of net proceeds (assuming the midpoint of the price range set forth on the cover of this prospectus) from the sale of common stock offered by us, after deducting underwriting discounts and commissions and estimated offering expenses payable by us. Each $1.00 increase (decrease) in the public offering price would increase (decrease) our net proceeds by approximately $ million.

We intend to use a portion of the net proceeds we receive from this offering to repay the $ million of outstanding indebtedness under our credit facility and the remaining net proceeds to fund a portion of our 2017 capital program. As of April 10, 2017, we had $380.0 million of outstanding borrowings under our credit facility and $5.0 million in outstanding letters of credit. Please read “Use of Proceeds”.

Conflicts of interest

An affiliate of Merrill Lynch, Pierce, Fenner & Smith Incorporated is a lender under our credit facility and will receive more than 5% of the net proceeds of this offering due to the repayment of borrowings thereunder. Accordingly, this offering will be conducted in accordance with Financial Industry Regulatory Authority (“FINRA”) Rule 5121. This rule requires, among other things, that a qualified independent underwriter has participated in the preparation of, and has exercised the usual standards of “due diligence” in respect to, the registration statement and this prospectus. has agreed to act as qualified independent underwriter for the offering and to undertake the legal responsibilities and liabilities of an underwriter under the Securities Act, specifically those inherent in Section 11 of the Securities Act. Please read “Underwriting (Conflicts of Interest)”.

Dividend policy

We do not anticipate paying any cash dividends on our common stock. In addition, our credit agreement places certain restrictions on our ability to pay cash dividends. Please read “Dividend Policy”.

Reserved share program

The underwriters have reserved for sale at the initial public offering price up to % of the common stock being offered by this prospectus for sale to our employees, executive officers, directors, director nominees, business associates and related persons who have expressed an interest in purchasing common stock in this offering. We do not know if these persons will choose to purchase all or any portion of these reserved shares, but any purchases they do make will reduce the number of shares available to the general public. Please read “Underwriting (Conflicts of Interest)”.

Listing and trading symbol

We have applied to list our common stock on the NYSE under the symbol “TE”.

Risk factors

You should carefully read and consider the information set forth under the heading “Risk Factors” and all other information set forth in this prospectus before deciding to invest in our common stock.

The information above does not include shares of common stock reserved for issuance pursuant to the Tapstone Energy Inc. 2017 Long-Term Incentive Plan.

Summary Historical Financial Data

The following table shows the summary historical consolidated financial data for the periods and as of the dates indicated, of Tapstone Energy, LLC, our accounting predecessor. The summary historical consolidated financial data of our predecessor as of and for the years ended December 31, 2016 and 2015 were derived from the audited historical consolidated financial statements of our predecessor included elsewhere in this prospectus.

Our historical results are not necessarily indicative of future results. You should read the following table in conjunction with “Use of Proceeds”, “Capitalization”, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the historical consolidated financial statements of our predecessor and accompanying notes included elsewhere in this prospectus.


	Year Ended December 31,
	2016			2015
	(in thousands, except per share data)
Statement of Operations Data:
Revenues:
Oil sales	$	74,675		$	86,082
Natural gas sales		65,577			73,662
Natural gas sales, related parties		8,747			8,017
NGL sales		36,189			31,406
Transportation revenue		3,916			4,711

Total revenues		189,104			203,878

Expenses:
Production expense		72,687			64,771
Production taxes		4,329			8,274
Transportation cost of service		5,858			6,166
Depreciation and depletion – oil and natural gas		59,855			80,178
Depreciation and amortization – other		8,204			7,561
Accretion of asset retirement obligation		460			422
Impairment of oil and natural gas properties		237,378			282,469
General and administrative		9,749			11,688
General and administrative, related parties		5,060			4,549

Total expenses		403,580			466,078

Loss from operations		(214,476	)		(262,200	)

Other income (expense):
Interest expense		(12,643	)		(12,249	)
Gain/(Loss) on derivative contracts		(17,449	)		47,839
Other income, net		81			15

Total other income (expense)		(30,011	)		35,605

Net loss	$	(244,487	)	$	(226,595	)


	Year Ended December 31,
	2016			2015
	(in thousands, except per share data)
Pro Forma Information (1):
Net loss	$	(244,487	)
Pro forma benefit for income taxes		39,370

Pro forma net loss	$	(205,117	)

Pro forma loss per common share
Basic and diluted	$
Weighted average pro forma shares outstanding
Basic and diluted
Statements of Cash Flows Data:
Cash provided by (used in):
Operating activities	$	134,633		$	195,536
Investing activities		(190,646	)		(196,385	)
Financing activities		50,079			(2,500	)
Balance Sheets Data (at period end):
Cash and cash equivalents	$	529		$	6,463
Total assets		630,570			803,416
Long-term obligations		357,117			414,668
Total liabilities		413,905			457,017
Total members’ equity		216,665			346,399
Other Financial Data:
Adjusted EBITDA (2)	$	140,799		$	184,306

(1)

The pro forma net loss per common share and weighted average pro forma shares outstanding reflect the estimated number of shares of common stock we expect to have outstanding upon the completion of our corporate reorganization described under “Corporate Reorganization”. The pro forma per-share data also reflects additional pro forma income tax benefit of $ million for the year ended December 31, 2016, associated with the income tax effects of the corporate reorganization described under “Corporate Reorganization” and this offering. Tapstone Energy Inc. is taxable as a corporation under the Internal Revenue Code of 1986, as amended (the “Code”), and as a result, will be subject to U.S. federal, state and local income taxes. Although our predecessor was subject to franchise tax in the State of Texas, it was treated as a partnership under the Code and generally passed through its taxable income to its owners for income tax purposes and thus was not subject to U.S. federal income taxes or other state or local income taxes.

(2)	Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to net income, see “—Non-GAAP Financial Measure—Adjusted EBITDA” below.

Non-GAAP Financial Measure

Adjusted EBITDA

Adjusted EBITDA is a supplemental non-GAAP financial measure that is used by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies.

oil and natural gas properties, income taxes, mark-to-market (“MTM”) gains or losses on derivative contracts, incentive unit compensation cost and acquisition and divestiture (“A&D”) costs. Adjusted EBITDA is not a measure of net income as determined by United States Generally Accepted Accounting Principles (“GAAP”).

Management believes Adjusted EBITDA is useful because it allows them to more effectively evaluate our operating performance and compare the results of our operations from period to period and against our peers without regard to our financing methods or capital structure. We exclude the items listed above from net income or net loss in arriving at Adjusted EBITDA because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDA should not be considered as an alternative to, or more meaningful than, net income (loss) as determined in accordance with GAAP or as an indicator of our operating performance. Certain items excluded from Adjusted EBITDA are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as the historic costs of depletable and depreciable assets, none of which are components of Adjusted EBITDA. Our presentation of Adjusted EBITDA should not be construed as an inference that our results will be unaffected by such items. Our computations of Adjusted EBITDA may not be comparable to other similarly titled measures of other companies.

The following table presents a reconciliation of Adjusted EBITDA to net income (loss), our most directly comparable financial measure calculated and presented in accordance with GAAP.


	Year Ended December 31,
	2016			2015
	(in thousands)
Net loss	$	(244,487	)	$	(226,595	)
Adjusted for
Interest expense		12,643			12,249
Depreciation and depletion – oil and natural gas		59,855			80,178
Depreciation and amortization – other		8,204			7,561
Accretion of asset retirement obligation		460			422
Impairment of oil and natural gas properties		237,378			282,469
Income taxes		—			—
Incentive unit compensation expense		4,757			4,705
MTM loss (gains) on derivative contracts (1)		61,356			21,093
A&D costs		633			2,224

Adjusted EBITDA	$	140,799		$	184,306

(1)	Includes the effect of adjusting net income (loss) for changes in the fair value of derivative instruments, which are recognized at the end of each accounting period because we do not designate commodity derivative instruments as cash flow hedges.

Summary Historical Reserve and Operating Data

The following tables present, for the periods and as of the dates indicated, summary data with respect to our net proved reserves and our production and operating data. The reserve estimates attributable to our properties presented in the table below were prepared based on reports by Ryder Scott, our independent petroleum engineers. The following tables also contain summary unaudited information regarding production and sales of oil, natural gas and NGLs with respect to such properties. Please read “Management’s Discussion and

Analysis of Financial Condition and Results of Operations” and “Business—Oil and Natural Gas Data—Proved Reserves” in evaluating the material presented below.


	NYMEX (1)			SEC (2)
	As of December 31, 2016
Proved Developed Reserves:
Oil (MBbls)		8,580			7,734
Natural gas (MMcf)		279,402			243,766
NGLs (MBbls)		20,244			17,266

Total (MBoe) (3)		75,391			65,628
Proved Undeveloped Reserves:
Oil (MBbls)		10,930			10,315
Natural gas (MMcf)		153,202			142,444
NGLs (MBbls)		10,598			9,863

Total (MBoe) (3)		47,062			43,919
Total Proved Reserves:
Oil (MBbls)		19,510			18,049
Natural gas (MMcf)		432,604			386,210
NGLs (MBbls)		30,842			27,129

Total (MBoe) (3)		122,453			109,546
Oil and Natural Gas Prices:
Oil – WTI posted price per Bbl		NA		$	42.75
Natural gas – Henry Hub spot price per MMBtu		NA		$	2.49
Standardized Measure (in thousands) (4)		—		$	320,720
Pro Forma Standardized Measure (in thousands) (5)		—		$	254,699
PV-10 (in thousands) (6)	$	670,334		$	322,682
Proved Developed % of Total Proved PV-10		67	%		79	%
Proved Undeveloped % of Total Proved PV-10		33	%		21	%

(1)

Our estimated net proved NYMEX reserves were prepared on the same basis as our SEC reserves, except for the use of hydrocarbon pricing based on closing monthly futures prices as reported on the NYMEX for oil and natural gas on January 1, 2017 rather than using the average of the first-day-of-the-month prices for the prior 12 months in accordance with SEC guidelines. Prices were in each case adjusted for gravity, quality, local conditions, gathering, transportation fees and distance from market.

Our NYMEX reserves were determined using index prices for oil and natural gas, without giving effect to derivative transactions. The average future prices for benchmark commodities used in determining our NYMEX reserves were $56.19/Bbl for 2017, $56.59/Bbl for 2018, $56.10/Bbl for 2019, $56.05/Bbl for 2020, $56.21/Bbl for 2021, $56.51/Bbl for 2022, $57.23/Bbl for 2023, $57.70/Bbl for 2024, $58.03/Bbl for 2025, and $58.10/Bbl for 2026 and thereafter for oil and $3.61/Mcf for 2017, $3.14/Mcf for 2018, $2.87/Mcf for 2019, $2.88/Mcf for 2020, $2.90/Mcf for 2021, $2.93/Mcf for 2022, $3.02/Mcf for 2023, $3.16/Mcf for 2024, $3.31/Mcf for 2025, and $3.68/Mcf for 2026 and thereafter for natural gas. NGLs pricing used in determining our NYMEX reserves were approximately 35% of future oil prices.

We believe that the use of forward prices provides investors with additional useful information about our reserves, as the forward prices are based on a market-based expectation of oil and natural gas prices as of a certain date. NYMEX futures prices are not necessarily a projection of future oil and natural gas prices. Our estimated net proved NYMEX reserves are intended to illustrate reserve sensitivities to market expectations of commodity prices as of a certain date and should not be confused with SEC prices. Investors should be careful to consider forward prices in addition to, and not as a substitute for, SEC prices, when considering our oil, natural gas and NGLs reserves.

(2)

Our estimated net proved reserves were determined using average first-day-of-the-month prices for the prior twelve months in accordance with SEC guidance. For oil and NGLs volumes, the average WTI posted price of $42.75 per barrel as of December 31, 2016, was adjusted for gravity, quality, local conditions, gathering, transportation fees and distance from market. For natural gas volumes, the average Henry Hub spot price of $2.49 per MMBtu as of December 31, 2016, was similarly adjusted for gravity, quality, local conditions, gathering, transportation fees and distance from market. All prices are held constant throughout the lives of the properties. The average adjusted product prices weighted by production over the remaining lives of the properties were $41.85 per barrel of oil, $14.94 per barrel of NGLs and $2.35 per Mcf of natural gas as of December 31, 2016.

(3)	Totals may not sum or recalculate due to rounding.

(4)

As of December 31, 2016, we were a limited liability company and as a result, we were not subject to entity-level U.S. federal, state and local income taxes, other than the franchise tax in the State of Texas. Following our corporate reorganization, we will be subject to U.S. federal, state and local income taxes. Accordingly, estimates included herein of future net cash flows may be materially different from the future net cash flows that are ultimately received. Future calculations of standardized measure will include the effects of income taxes on future net cash flow. Please read “Risk Factors—The standardized measure of our estimated reserves is not an accurate estimate of the current fair value of our estimated reserves”.

(5)

(6)

PV-10 is not a financial measure calculated or presented in accordance with 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. Because Tapstone Energy, LLC has not been subject to entity level U.S. federal, state and local income taxes, other than the franchise tax in the State of Texas, prior to this offering, as of December 31, 2016, the PV-10 value and standardized measure of our properties were substantially equal. Following our corporate reorganization, we will be subject to U.S. federal, state and local income taxes. Accordingly, estimates included herein of future net cash flows may be materially different from the future net cash flows that are ultimately received. Future calculations of standardized measure will include the effects of income taxes on future net cash flow. Please read “Risk Factors—The standardized measure of our estimated reserves is not an accurate estimate of the current fair value of our estimated reserves”. 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.


	Year Ended December 31,
	2016		2015
Production and Operating Data:
Production:
Oil (MBbls)		1,860		1,895
Natural gas (MMcf)		32,484		31,024
NGLs (MBbls)		2,553		2,476

Total (MBoe) (1)		9,827		9,542

Average sales price before impact of cash-settled derivatives:
Oil (per Bbl)	$	40.15	$	45.42
Natural gas (per Mcf)		2.29		2.63
NGLs (per Bbl)		14.17		12.68

Average (per Boe)	$	18.84	$	20.87

Average sales price after impact of cash-settled derivatives:
Oil (per Bbl)	$	48.40	$	63.84
Natural gas (per Mcf)		2.92		3.40
NGLs (per Bbl)		17.33		16.83

Average (per Boe)	$	23.31	$	28.10

Operating expenses (per Boe):
Production expenses	$	7.40	$	6.79
Production taxes		0.44		0.87
Depreciation and depletion – oil and natural gas		6.09		8.40
Impairment of oil and natural gas properties		24.16		29.60
General and administrative (2)		1.51		1.70

Total (per Boe)	$	39.59	$	47.36

(1)	Total may not sum or recalculate due to rounding.

(2)	General and administrative does not include additional expenses we would have to incur as a result of being a public company.

RISK FACTORS

Investing in our common stock involves risks. You should carefully consider all of the information in this prospectus, including the matters addressed under “Cautionary Statement Regarding Forward-Looking Statements” and the following risks, before making an investment decision. Our business, financial condition and results of operations could be materially and adversely affected by, and the trading price of our common stock could decline, due to any of these risks, and you may lose all or part of your investment. The risks described below are not the only ones facing us. Additional risks not presently known to us or which we consider immaterial may also adversely affect us.

Risks Related to Our Business

Oil, natural gas and NGLs are commodities, and their prices may fluctuate widely in response to market uncertainty and relatively minor changes in the supply of and demand for oil, natural gas and NGLs. Historically, oil, natural gas and NGLs prices have been volatile. For example, during the period from January 1, 2014 through March 23, 2017, the WTI posted price for oil has declined from a high of $107.95 per Bbl on June 20, 2014, to $26.19 per Bbl on February 11, 2016, and the Henry Hub spot price for natural gas has declined from a high of $8.15 per MMBtu on February 10, 2014, to a low of $1.49 per MMBtu on March 4, 2016. Likewise, NGLs, which are comprised of ethane, propane, isobutene, normal butane and natural gasoline, all of which have different uses and different pricing characteristics, have suffered significant recent declines in realized prices. The prices we receive for our oil, natural gas and NGLs production heavily influence our revenue, profitability, access to capital, future rate of growth and carrying value of our properties. The prices we receive for our production, and the levels of our production, depend on numerous factors beyond our control, which include the following:

•

worldwide and regional political or economic conditions impacting the global supply and demand for oil, natural gas and NGLs;

•

the price and quantity of foreign imports of oil, natural gas and NGLs;

•

political and economic conditions in or affecting other producing regions or countries, including the Middle East, Africa, South America and Russia;

•

actions of the Organization of the Petroleum Exporting Countries (“OPEC”), its members and state-controlled oil companies relating to oil price and production controls;

•

the level of global exploration, development and production;

•

the level of global inventories of oil;

•

prevailing commodity prices on local price indexes in the area in which we operate;

•

the proximity, capacity, cost and availability of gathering and transportation facilities;

•

localized and global supply and demand fundamentals and transportation availability;

•

the cost of exploring for, developing and producing reserves and transporting production;

•

weather conditions and other natural disasters;

•

technological advances affecting energy consumption and production;

•

the price and availability of alternative fuels;

•

expectations about future commodity prices; and

•

U.S. federal, state and local and non-U.S. governmental regulation and taxes.

In the second half of 2014, oil prices began a rapid and significant decline as the global oil supply began to outpace demand. During 2015 and 2016, the global oil supply continued to outpace demand, resulting in a sustained decline in realized prices for oil production. In general, this imbalance between supply and demand reflects the significant supply growth achieved in the United States as a result of shale drilling and oil production increases by certain other countries, including Russia and Saudi Arabia, as part of an effort to retain market share, combined with only modest demand growth in the United States and less-than-expected demand in other parts of the world. Although there has been a dramatic decrease in drilling activity in the industry, oil storage levels in the United States remain at historically high levels. Until supply and demand balance and the overhang in storage levels begins to decline, prices will likely remain under pressure. The U.S. dollar has also strengthened relative to other leading currencies, which has caused oil prices to weaken, as they are U.S. dollar-denominated. In addition, the lifting of economic sanctions on Iran has resulted in increasing supplies of oil, adding further downward pressure to oil prices. Oil prices experienced considerable volatility during the third quarter 2016, with the WTI posted price falling to a low of $39.50 per barrel in early August before rebounding on the news that OPEC had agreed to the framework of an agreement that would limit production by its member countries. Oil prices continued to rise in the fourth quarter 2016 and thus far in 2017 as OPEC formally announced its agreement to cut production by 1,200 MBbl/d on November 30, 2016, followed by the announcement in December that certain non-OPEC countries, including Russia, Mexico, Azerbaijan, Oman and Kazakhstan, had agreed to cut production by 558 MBbl/d. NGLs prices generally correlate to the price of oil. Also adversely affecting the price for NGLs is the supply of NGLs in the United States, which has continued to grow due to an increase in industry participants targeting the development of NGLs-prone acreage in recent years. Prices for domestic natural gas began to decline during the third quarter of 2014 and remained weak throughout 2015, 2016 and thus far in 2017. The declines in natural gas prices are primarily due to an imbalance between supply and demand across North America. Although the current downturn has begun to show signs of improvement, any long-term recovery continues to be uncertain and is dependent on a number of economic, geopolitical and monetary policy factors that are outside our control, and the market is likely to continue to be volatile in the future.

Lower commodity prices may reduce our cash flows and borrowing ability. If we are unable to obtain needed capital or financing on satisfactory terms, our ability to develop our reserves could be adversely affected. Furthermore, using lower prices in estimating proved reserves may result in a reduction in proved reserve volumes due to economic limits. In addition, sustained periods with oil and natural gas prices at levels lower than current WTI or Henry Hub prices may adversely affect our drilling economics and our ability to raise capital, which may require us to re-evaluate and postpone or eliminate our development drilling, and result in the reduction of some of our proved undeveloped reserves and related standardized measure. If we are required to curtail our drilling program, we may be unable to continue to hold leases that are scheduled to expire, which may further reduce our reserves. As a result, a further reduction or sustained decline in commodity prices may materially and adversely affect our future business, financial condition, results of operations, liquidity and ability to finance planned capital expenditures.

The oil and natural gas industry is capital intensive. We make and expect to continue to make substantial capital expenditures related to our development plan and acquisitions. In addition, our production costs may increase as we use enhanced drilling and completion techniques and other new drilling technologies, which are capital intensive and may not produce oil and natural gas in paying quantities or at all. Further, we from time to time evaluate potential acquisition opportunities, and any such acquisitions we pursue could require substantial capital expenditures. Our 2017 capital budget is approximately $257 million. We expect to fund our capital expenditures with cash generated by operations, borrowings under our credit facility and a portion of the proceeds from this offering; however, our financing needs may require us to alter or increase our capitalization substantially through the issuance of debt or equity securities or the sale of assets. The issuance of additional indebtedness would require that a portion of our cash flow from operations be used for the payment of interest and principal on our indebtedness, thereby reducing our ability to use cash flow from operations to fund working capital, capital expenditures and acquisitions. The issuance of additional equity securities would be dilutive to all stockholders. The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other things, oil, natural gas and NGLs prices; actual drilling results; the availability of drilling rigs and other services and equipment; and regulatory, technological and competitive developments. A reduction in commodity prices from current levels may result in a decrease in our actual capital expenditures, which would negatively impact our ability to grow production.

Our cash flow from operations and access to capital are subject to a number of variables, including:

•

the prices at which our production is sold;

•

the levels of our operating expenses;

•

the level of hydrocarbons we are able to produce from existing wells;

•

our proved reserves;

•

our ability to acquire, locate and produce new reserves; and

•

our ability to borrow under our credit facility and our ability to access the capital markets.

If our revenues or the borrowing base under our credit facility decrease as a result of lower oil, natural gas and NGLs prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels. If additional capital is needed, we may not be able to obtain debt or equity financing on terms acceptable to us, if at all. For a period of 180 days following the date of this prospectus, we will not be able to sell any shares of our common stock, whether pursuant to a private or public offering, without the prior written consent of Merrill Lynch, Pierce, Fenner & Smith Incorporated and Citigroup Global Markets Inc. Please read “Underwriting (Conflicts of Interest)” for more information. If cash flow generated by our operations or available borrowings under our credit facility are 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 properties, which in turn could lead to a decline in our reserves and production, and could materially and adversely affect our business, financial condition and results of operations.

Part of our strategy involves using some of the latest available horizontal drilling and completion techniques, which involve risks and uncertainties in their application.

Our operations involve utilizing some of the latest available drilling and completion techniques as developed by us and our service providers. The difficulties we face while drilling horizontal wells include:

•

landing our wellbore in the desired drilling zone;

•

staying in the desired drilling zone while drilling horizontally through the formation;

•

running our casing the entire length of the wellbore; and

•

being able to run tools and other equipment consistently through the horizontal wellbore.

The difficulties we face while completing our wells include:

•

the ability to fracture stimulate the planned number of stages;

•

the ability to run tools the entire length of the wellbore during completion operations; and

•

the ability to successfully clean out the wellbore after completion of the final fracture stimulation stage.

Additionally, 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. If our drilling results in less production than anticipated, the return on our investment for a particular project may not be as attractive as we anticipated, we could incur material write-downs of unevaluated properties, and the value of our undeveloped acreage could decline in the future.

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, please read “—Reserve estimates depend on many assumptions that may turn out to be inaccurate. 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 activity, including the following:

•

delays imposed by or resulting from compliance with regulatory requirements, including limitations on wastewater disposal, additional regulation related to seismic activity, water disposal, discharge of greenhouse gases (“GHGs”) and limitations on hydraulic fracturing;

•

pressure or irregularities in geological formations;

•

shortages of or delays in obtaining equipment and qualified personnel or in obtaining materials required for our drilling activities, including water for hydraulic fracturing activities;

•

equipment failures, accidents or other unexpected operational events;

•

lack of available and economic gathering and takeaway capacity, including gathering facilities and interconnecting transmission pipelines;

•

adverse weather conditions;

•

issues related to compliance with environmental regulations;

•

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;

•

declines in oil and natural gas prices;

•

limited availability of financing at acceptable terms;

•

title problems or legal disputes regarding leasehold rights; and

•

limitations in the market for oil and natural gas.

Furthermore, the results of drilling in new or emerging formations are more uncertain initially than drilling results in areas that are more developed and have a longer history of established production.

Finally, the presence of impurities in our produced natural gas (such as hydrogen sulfide (“H₂S”) or carbon dioxide (“CO₂”)) may adversely affect our ability to produce and market our natural gas and could cause our operating expenses to increase. If we encounter high levels of impurities in wells we drill it could negatively impact our results of operations, including reduced revenues associated with having to shut in wells while marketability is explored and treatment is put in place, increased operating expenses and a further reduction in potential drilling 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 drilling locations represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including oil and natural gas 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 uncertain factors, we do not know if the numerous drilling locations we have identified will ever be drilled or if we will be able to produce oil or natural gas from these or any other drilling locations. In addition, unless production is established within the spacing units covering the undeveloped acres on which some of the drilling locations are located, the leases for such acreage will expire. As such, our actual drilling activities may materially differ from those presently identified.

As of December 31, 2016, we had a drilling inventory consisting of 6,337 gross (2,912 net) identified horizontal drilling locations. As a result of the limitations described above, we may be unable to drill many of

our identified locations. In addition, we will require significant additional capital over a prolonged period in order to pursue the development of these locations, and we may not be able to raise or generate the capital required to do so. Please read “—Our development plan and acquisitions require substantial capital expenditures. We may be unable to generate sufficient cash from operations or obtain required capital or financing on satisfactory terms, which could lead to a decline in our ability to access or grow production and reserves”. Any drilling activities we are able to conduct on these locations may not be successful or result in our ability 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. Additionally, if we curtail our drilling program, we may lose a portion of our acreage through lease expirations.

The process of estimating reserves is complex. It requires interpretations of available technical data and many assumptions, including assumptions relating to current and future economic conditions and commodity prices. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of our reserves. In order to prepare reserve estimates, we must project production rates and timing of development expenditures. We must also analyze available geological, geophysical, production and engineering data. The extent, quality and reliability of this data can vary. The process also requires economic assumptions about matters such as oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds.

Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable reserves may vary from our estimates. For instance, initial production rates reported by us or other operators may not be indicative of future or long-term production rates, our recovery efficiencies may be worse than expected and production declines may be greater than we estimate and may be more rapid and irregular when compared to initial production rates. In addition, we may adjust reserve estimates to reflect additional production history, results of development activities, current commodity prices and other existing factors. Any significant variance could materially affect the estimated quantities and present value of our reserves. Moreover, there can be no assurance that our reserves will ultimately be produced or that our proved undeveloped reserves will be developed within the periods anticipated.

You should not assume that the present value of future net cash flows from our reserves is the current market value of our estimated reserves. We generally base the estimated discounted future net cash flows from reserves on prices and costs on the date of the estimate. Actual future prices and costs may differ materially from those used in the present value estimate. For example, our estimated proved reserves as of December 31, 2016, and related standardized measure were calculated under SEC rules using twelve-month trailing average benchmark prices of $42.75 per barrel of oil (WTI posted) and $2.49 per MMBtu (Henry Hub spot), which, for certain periods in 2016, were substantially higher than the available spot prices. If spot prices are below such calculated amounts, using more recent prices in estimating proved reserves may result in a reduction in proved reserve volumes due to economic limits.

Unless we replace our reserves with new reserves and develop those reserves, our reserves and production will decline, which would adversely affect our future cash flows and results of operations.

Producing oil and natural gas reservoirs are generally characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Unless we conduct successful ongoing exploration and development activities or continually acquire properties containing proved reserves, our proved reserves will decline as those reserves are produced. Our future reserves and production, and therefore our future cash flow and results of operations, are highly dependent on our success in efficiently developing our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop,

find or acquire sufficient additional reserves to replace our current and future production. If we are unable to replace our current and future production, the value of our reserves will decrease, and our business, financial condition and results of operations would be materially and adversely affected.

Operating our midstream system involves significant risks, including those related to cost overruns, operational efficiency and mechanical failures.

Operating Wheeler Midstream involves significant risks, including those related to cost overruns, operational efficiency and mechanical failures. These risks can be affected by the availability of capital, materials and qualified personnel, as well as weather conditions, commodity price volatility, delays in obtaining rights-of-way, permits and other government approvals, title and property access problems, geology and other factors.

Our ability to make scheduled payments on or to refinance our indebtedness obligations, including our credit facility, which matures in 2019, depends on our financial condition and operating performance, which are subject to prevailing economic and competitive conditions and certain financial, business and other factors beyond our control. We may not be able to maintain a level of cash flows from operating activities sufficient to permit us to pay the principal, premium, if any, and interest on our indebtedness.

If our cash flows and capital resources are insufficient to fund debt service obligations, we may be forced to reduce or delay investments and capital expenditures, sell assets, seek additional capital or restructure or refinance indebtedness. Our ability to restructure or refinance indebtedness will depend on the condition of the capital markets and our financial condition at such time. Any refinancing of indebtedness could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict business operations. The terms of existing or future debt instruments may restrict us from adopting some of these alternatives. In addition, any failure to make payments of interest and principal on outstanding indebtedness on a timely basis would likely result in a reduction of our credit rating, which could harm our ability to incur additional indebtedness. In the absence of sufficient cash flows and capital resources, we could face substantial liquidity problems and might be required to dispose of material assets or operations to meet debt service and other obligations. We may not be able to consummate those dispositions, and the proceeds of any such disposition may not be adequate to meet any debt service obligations then due. These alternative measures may not be successful and may not permit us to meet scheduled debt service obligations.

Restrictions in our existing and future debt agreements could limit our growth and our ability to engage in certain activities.

Our credit agreement contains a number of significant covenants, including restrictive covenants that may limit our ability to, among other things:

•

incur additional indebtedness;

•

incur liens;

•

make investments;

•

make loans to others;

•

merge or consolidate with another entity;

•

sell assets;

•

make certain payments;

•

enter into transactions with affiliates;

•

enter into swap contracts; and

•

engage in certain other transactions without the prior consent of the lenders.

In addition, our credit agreement requires us to maintain certain financial ratios or to reduce our indebtedness if we are unable to comply with such ratios.

The restrictions in our credit agreement may also limit our ability to obtain future financings to withstand a future downturn in our business or the economy in general, to maintain cash balances in excess of certain specified threshold amounts or to otherwise conduct necessary corporate activities. We may also be prevented from taking advantage of business opportunities that arise because of the limitations that the restrictive covenants under our credit agreement impose on us.

A breach of any covenant in our credit agreement would result in a default under the applicable agreement after any applicable grace periods. A default, if not waived or cured, could result in acceleration of the indebtedness outstanding under our credit agreement and in a default with respect to, and an acceleration of, the indebtedness outstanding under other debt agreements. The accelerated indebtedness would become immediately due and payable. 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.

Our credit facility limits the amounts we can borrow up to a borrowing base amount, which the lenders, in their sole discretion, determine semiannually on April 1 and October 1. The borrowing base depends on, among other things, the volumes of our proved reserves and estimated cash flows from these reserves and our commodity hedge positions as well as any other outstanding debt. The value of our proved reserves is dependent upon, among other things, the prevailing and expected market prices of the underlying commodities in our estimated reserves. Please read “—Oil, natural gas and NGLs prices are volatile and have seen significant declines in recent years. A further reduction or sustained decline in oil, natural gas and NGLs prices could adversely affect our business, financial condition and results of operations and our ability to meet our capital expenditure obligations and financial commitments”, and “—Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves”. The lenders can unilaterally adjust the borrowing base and the borrowings permitted to be outstanding under our credit facility. Any increase in the borrowing base requires the consent of the lenders holding 100% of the commitments. Our borrowing base was $385.0 million as of April 10, 2017. Our next scheduled borrowing base redetermination is expected on or about October 1, 2017. However, the lenders will redetermine the borrowing base under our credit facility if we have not applied at least $250 million in net proceeds from this offering to prepay loans outstanding under the credit facility on or prior to May 15, 2017.

In the future, we may not be able to access adequate funding under our credit facility as a result of a decrease in borrowing base due to the issuance of new indebtedness, the outcome of a subsequent borrowing base redetermination or an unwillingness or inability on the part of lending counterparties to meet their funding obligations and the inability of other lenders to provide additional funding to cover the defaulting lender’s portion. Declines in commodity prices could result in a determination to lower the borrowing base in the future and, in such a case, we could be required to repay any indebtedness in excess of the redetermined borrowing

base. As a result, we may be unable to implement our drilling and development plan, make acquisitions or otherwise carry out business plans, which would have a material adverse effect on our financial condition and results of operations and impair our ability to service our indebtedness.

As of December 31, 2016, approximately 41% of our total net acreage was held by production or drilling operations. The leases for our net acreage not held by production will expire at the end of their primary term unless production is established in paying quantities under the units containing these leases, we pay the lessees option payments on some of the leases to extend the leases for an additional two years or the leases are renewed. If our leases expire and we are unable to renew the leases, we will lose our right to develop the related properties. Our ability to drill and develop these locations depends on a number of uncertainties, including oil and natural gas 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.

Our derivative activities could result in financial losses or could reduce our earnings.

We enter into derivative instrument contracts for a portion of our oil, natural gas and NGLs production. Accordingly, our earnings may fluctuate significantly as a result of changes in fair value of any derivative instruments.

Derivative instruments also expose us to the risk of financial loss in some circumstances, including when:

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production is less than the volume covered by the derivative instruments;

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the counterparty to the derivative instrument defaults on its contractual obligations;

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there is an increase in the differential between the underlying price in the derivative instrument and actual prices received; or

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there are issues with regard to legal enforceability of such instruments.

The use of derivatives may, in some cases, require the posting of cash collateral with counterparties. If we enter into derivative instruments that require cash collateral and commodity prices or interest rates change in a manner adverse to us, our cash otherwise available for use in our operations would be reduced which could limit our ability to make future capital expenditures and make payments on our indebtedness, and which could also limit the size of our borrowing base. Future collateral requirements will depend on arrangements with our counterparties, highly volatile oil and natural gas prices and interest rates. In addition, derivative arrangements could limit the benefit we would receive from increases in the prices for oil and natural gas, which could also have a material adverse effect on our financial condition. Alternatively, higher oil and natural gas prices may result in significant non-cash fair value losses being incurred on our derivatives, which could cause us to experience net losses associated with those hedging contracts when oil and natural gas prices rise.

Our commodity derivative contracts expose us to risk of financial loss if a counterparty fails to perform under a contract. Disruptions in the financial markets could lead to sudden decreases in a counterparty’s liquidity, which could make the counterparty unable to perform under the terms of the contract, and we may not be able to realize the benefit of the contract. We are unable to predict sudden changes in a counterparty’s creditworthiness or ability to perform. Even if we do accurately predict sudden changes, our ability to negate the risk may be limited depending upon market conditions.

During periods of declining commodity prices, our derivative contract receivable positions generally increase, which increases our counterparty credit exposure. If the creditworthiness of our counterparties deteriorates and results in their nonperformance, we could incur a significant loss with respect to our commodity derivative contracts.

As of December 31, 2016, we were the operator on 3,235 of our 6,337 gross identified horizontal drilling locations. We will have limited ability to exercise influence over the operations of the drilling locations operated by other working interest owners, and there is the risk that in such case the operator may at any time have economic, business or legal interests or goals that are inconsistent with ours. Furthermore, the success and timing of development activities operated by other parties will depend on a number of factors that will be largely outside of our control, including:

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the timing and amount of capital expenditures;

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the operator’s expertise and financial resources;

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the approval of other participants in drilling wells;

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the selection of technology; and

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the rate of production of reserves, if any.

This limited ability to exercise control over the operations and associated costs of some of our drilling locations could prevent the realization of targeted returns on capital in drilling or acquisition activities.

Adverse weather conditions may negatively affect our operating results and our ability to conduct drilling activities.

Adverse weather conditions may cause, among other things, increases in the costs of, and delays in, drilling or completing new wells, power failures, temporary shut-in of production and difficulties in the transportation of our oil, natural gas and NGLs. Any decreases in production due to poor weather conditions will have an adverse effect on our revenues, which will in turn negatively affect our cash flow from operations.

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 oil and natural gas development during both the drilling and hydraulic fracturing processes. Drought conditions have persisted in certain of our areas of operation in past years. These drought conditions have led governmental authorities to regulate the use of water subject to their jurisdiction for hydraulic fracturing to protect local water supplies. If we are unable to obtain water to use in our operations, we may be unable to economically produce oil and natural gas, which could have a material and adverse effect on our financial condition, results of operations and cash flows.

Our producing properties are located in the Anadarko Basin in Oklahoma, Texas and Kansas, making us vulnerable to risks associated with operating in a single geographic area.

All of our producing properties are geographically concentrated in the Anadarko Basin in Oklahoma, Texas and Kansas. At December 31, 2016, all of our total estimated proved reserves were attributable to

properties located in this area. As a result of this concentration, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in this area caused by governmental regulation, processing or transportation capacity constraints, market limitations, availability of equipment and personnel, water shortages or other drought related conditions or interruption of the processing or transportation of oil, natural gas or NGLs. Such delays or interruptions could have a material adverse effect on our financial condition and results of operations.

The marketability of our oil and natural gas production depends in part upon the availability, proximity and capacity of transportation facilities owned by third-parties. Insufficient production from our wells to support the construction of pipeline facilities by our customers or a significant disruption in the availability of our or third-party transportation facilities or other production facilities could adversely impact our ability to deliver to market or produce our oil and natural gas and thereby cause a significant interruption in our operations. If, in the future, we are unable, for any sustained period, to implement acceptable delivery or transportation arrangements or encounter production related difficulties, we may be required to shut in or curtail production. Any such shut in or curtailment, or an inability to obtain favorable terms for delivery of the oil and natural gas produced from our fields, would materially and adversely affect our financial condition and results of operations.

We may incur losses as a result of title defects in the properties in which we invest.

The existence of a material title deficiency can render a lease worthless and can adversely affect our results of operations and financial condition. While we typically obtain title opinions prior to commencing drilling operations on a lease or in a unit, the failure of title may not be discovered until after a well is drilled, in which case we may lose the lease and the right to produce all or a portion of the interest under the property.

As of December 31, 2016, approximately 40.1% of our total estimated proved reserves were classified as proved undeveloped. Development of these proved undeveloped reserves may take longer and require higher levels of capital expenditures than we currently anticipate. Delays in the development of our reserves, increases in costs to drill and develop such reserves or decreases in commodity prices will reduce the value of our estimated PUDs and future net cash flows estimated for such reserves and may result in some projects becoming uneconomic. In addition, delays in the development of reserves could cause us to lose leases through expiration or have to reclassify our PUDs as unproved reserves. Further, we may be required to write-down our PUDs if we do not drill those wells within five years after their respective dates of booking.

Our method of accounting for investments in oil and natural gas properties may result in ceiling test write-downs, which could negatively impact our results of operations.

We account for our oil and natural gas producing activities using the full cost method of accounting. Accordingly, all costs incurred in the acquisition, exploration and development of proved oil and natural gas properties, including the costs of abandoned properties, dry holes, geophysical costs and annual lease rentals are capitalized. All general and administrative corporate costs unrelated to acquisition, exploration and development activities are expensed as incurred. Sales or other dispositions of oil and natural gas properties are generally accounted for as adjustments to capitalized costs, with no gain or loss recorded unless the ratio of cost to proved reserves would significantly change. Depletion of evaluated oil and natural gas properties is computed on the units of production method based on proved reserves. Our average depletion rate per Boe of production was

$6.09 for 2016. The total depletion expense for our oil and natural gas properties was $59.9 million for 2016. The net capitalized costs of proved oil and natural gas properties are subject to a full cost ceiling limitation in which the costs are not allowed to exceed their related estimated future net cash flows discounted at 10%. The excess, if any, of the net book value above the ceiling limitation is charged to expense in the period in which it occurs and is not subsequently reinstated.

Accounting rules require that we review the net capitalized costs of our properties quarterly, using a single price based on the beginning-of-the-month average of oil and natural gas prices for the preceding twelve months. We also assess investments in unproved properties periodically to determine whether impairment has occurred. The risk that we will be required to further write down the carrying value of our oil and natural gas properties increases when oil and natural gas prices are low or volatile. In addition, write-downs may occur if we experience substantial downward adjustments to our estimated proved reserves or our unproved property values, or if estimated future development costs increase. Our predecessor incurred approximately $237.4 million and $282.5 million of impairment of oil and natural gas property charges during 2016 and 2015, respectively. Historically, oil, natural gas and NGLs prices have been volatile. For example, during the period from January 1, 2014 through March 23, 2017, the WTI posted price for oil has declined from a high of $107.95 per Bbl on June 20, 2014, to $26.19 per Bbl on February 11, 2016, and the Henry Hub spot price for natural gas has declined from a high of $8.15 per MMBtu on February 10, 2014, to a low of $1.49 per MMBtu on March 4, 2016. Lower commodity prices in the future could result in further impairments of our properties, which could have a material adverse effect on our results of operations for the periods in which such charges are taken. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates” for a more detailed description of our method of accounting.

Conservation measures and technological advances could reduce demand for oil and natural gas.

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.

We depend upon several significant customers for the sale of most of our oil, natural gas and NGLs production.

We sell our production to a relatively small number of customers, as is customary in our business. For the year ended December 31, 2016, three customers accounted for more than 10% of our revenue: Plains Marketing (42%), Enable (16%) and Spire Marketing Inc. (“Spire”) (14%). For the year ended December 31, 2015, two customers accounted for more than 10% of our revenue: Plains Marketing (48%) and Spire (17%). During such periods, no other customer accounted for 10% or more of our revenue. The loss of any of these customers, or the failure of any of these customers to live up to their contractual obligations to us, could materially and adversely affect our revenues.

Our operations may be exposed to significant delays, costs and liabilities as a result of environmental and occupational health and safety requirements applicable to our business activities.

Our operations are subject to stringent and complex federal, state and local laws and regulations governing the discharge of materials into the environment, health and safety aspects of our operations or otherwise relating to environmental protection. These laws and regulations may impose numerous obligations applicable to our operations, including the acquisition of a permit or other approval before conducting regulated activities; the restriction of types, quantities and concentration of materials that can be released into the environment; the limitation or prohibition of drilling activities on certain lands lying within wilderness, wetlands and other protected areas; the application of specific health and safety criteria addressing worker protection; and the imposition of substantial liabilities for pollution resulting from our operations. Numerous governmental

authorities, such as the U.S. Environmental Protection Agency (“EPA”) and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them. Such enforcement actions often involve taking difficult and costly compliance measures or corrective actions. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil or criminal penalties, natural resource damages, the imposition of investigatory or remedial obligations and the issuance of orders limiting or prohibiting some or all of our operations. In addition, we may experience delays in obtaining, or be unable to obtain, required permits, which may delay or interrupt our operations and limit our growth and revenue.

Certain environmental laws impose strict as well as joint and several liability for costs required to remediate and restore sites where hazardous substances, hydrocarbons or solid wastes have been stored or released. We may be required to remediate contaminated properties currently or formerly operated by us or facilities of third parties that received waste generated by our operations regardless of whether such contamination resulted from the conduct of others or from consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken. In connection with certain acquisitions, we could acquire, or be required to provide indemnification against, environmental liabilities that could expose us to material losses. In addition, claims for damages to persons or property, including natural resources, may result from the environmental, health and safety impacts of our operations. Our insurance may not cover all environmental risks and costs or may not provide sufficient coverage if an environmental claim is made against us. Moreover, public interest in the protection of the environment has increased dramatically in recent years. The trend of more expansive and stringent environmental legislation and regulations applied to the crude oil and natural gas industry could continue, resulting in increased costs of doing business and consequently affecting profitability. For example, in May 2016, the EPA finalized rules regarding criteria for aggregating multiple small surface sites into a single source for air-quality permitting purposes applicable to the oil and natural gas industry. This rule could cause small facilities, on an aggregate basis, to be deemed a major source, thereby triggering more stringent air permitting processes and requirements. To the extent laws are enacted or other governmental action is taken that restricts drilling or imposes more stringent and costly permitting, operating, waste handling, disposal and cleanup requirements our business, prospects, financial condition or results of operations could be materially adversely affected.

We are not insured against all risks. Losses and liabilities arising from uninsured and underinsured events could materially and adversely affect our business, financial condition or results of operations.

Our development activities are subject to all of the operating risks associated with drilling for and producing oil and natural gas, including the possibility of:

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environmental hazards, such as uncontrollable releases of oil, natural gas, brine, well fluids, toxic gas or other pollution into the environment, including groundwater, air and shoreline contamination;

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encountering corrosive elements in the drilling, completion and production process, including but not limited to carbon dioxide and hydrogen sulfide, which may require special equipment and tubulars to safely and efficiently produce the oil and gas;

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abnormally pressured formations;

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mechanical difficulties, such as stuck oilfield drilling and service tools and casing collapse;

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fires, explosions and ruptures of pipelines;

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personal injuries and death;

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natural disasters, including earthquakes; and

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terrorist attacks targeting oil and natural gas related facilities and infrastructure.

Any of these risks could adversely affect our ability to conduct operations or result in substantial loss to us as a result of claims for:

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injury or loss of life;

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damage to and destruction of property, natural resources and equipment;

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pollution and other environmental damage;

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regulatory investigations and penalties;

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suspension of our operations; and

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repair and remediation costs.

We may elect not to obtain insurance for any or all of these risks if we believe that the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. The occurrence of an event that is not fully covered by insurance could have a material adverse effect on our business, financial condition and results of operations.

Properties that we decide to drill may not yield oil or natural gas in commercially viable quantities.

Properties that we decide to drill that do not yield oil or natural gas in commercially viable quantities will adversely affect our results of operations and financial condition. There is no way to predict in advance of drilling and testing whether any particular prospect will yield oil or natural gas in sufficient quantities to recover drilling or completion costs or to be economically viable. The use of technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in commercial quantities. We cannot assure you that the analogies we draw from available data from other wells, more fully explored prospects or producing fields will be applicable to our drilling prospects. Further, our drilling operations may be curtailed, delayed or cancelled as a result of numerous factors, including:

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unexpected drilling conditions;

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title problems;

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pressure or lost circulation in formations;

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equipment failure or accidents;

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adverse weather conditions;

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compliance with environmental and other governmental or contractual requirements; and

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increases in the cost of, shortages or delays in the availability of, electricity, supplies, materials, drilling or workover rigs, equipment and services.

We may be unable to successfully integrate acquired businesses, and any inability to do so may disrupt our business.

In the future we may make acquisitions of assets or businesses that complement or expand our current business. In the event we are able to identify attractive acquisition opportunities, we may not be able to complete the acquisition or do so on commercially acceptable terms. Competition for acquisitions may also increase the cost of completing acquisitions.

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. In addition, possible future acquisitions may be larger and for purchase prices significantly higher than those paid for earlier acquisitions. 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. Our failure to achieve consolidation savings, to integrate 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 credit agreement imposes certain limitations on our ability to enter into mergers or combination transactions. Our credit agreement also limits our ability to incur certain indebtedness, which could indirectly limit our ability to engage in acquisitions of businesses.

We may be subject to risks in connection with acquisitions of oil and natural gas properties.

The successful acquisition of oil and natural gas properties requires an assessment of several factors, including:

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recoverable reserves;

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future oil and natural gas prices and their applicable differentials;

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operating costs; and

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potential environmental and other liabilities.

The accuracy of these assessments is inherently uncertain. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices. Our review will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. Inspections may not always be performed on every well, and environmental problems, such as groundwater contamination, are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. We often are not entitled to contractual indemnification for environmental liabilities and acquire properties on an “as-is” basis.

Properties we acquire may not produce as projected, and we may be unable to determine reserve potential, identify liabilities associated with the properties that we acquire or obtain protection from sellers against such liabilities.

Acquiring oil and natural gas properties requires us to assess reservoir and infrastructure characteristics, including recoverable reserves, future oil and natural gas prices and their applicable differentials, development and operating costs, and potential liabilities, including environmental liabilities. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with

industry practices. Such assessments are inexact and inherently uncertain. For these reasons, the properties we have acquired or will acquire in the future may not produce as expected. In connection with the assessments, we perform a review of the subject properties, but such a review may not reveal all existing or potential problems. In the course of our due diligence, we may not review every well, pipeline or associated facility. We cannot necessarily observe structural and environmental problems, such as groundwater contamination, when a review is performed. We may be unable to obtain contractual indemnities from the seller for liabilities created prior to our purchase of the property. We may be required to assume the risk of the physical condition of the properties in addition to the risk that the properties may not perform in accordance with our expectations.

Certain of our properties are subject to land use restrictions, which could limit the manner in which we conduct our business.

Certain of our properties are subject to land use restrictions which could limit the manner in which we conduct our business. Such restrictions could affect, among other things, our access to and the permissible uses of our facilities as well as the manner in which we produce oil and natural gas and may restrict or prohibit drilling in general. The costs we incur to comply with such restrictions may be significant in nature, and we may experience delays or curtailment in the pursuit of development activities and perhaps even be precluded from the drilling of wells.

The demand for drilling rigs, pipe and other equipment and supplies, as well as for qualified and experienced field personnel to drill wells and conduct field operations, geologists, geophysicists, engineers and other professionals in the oil and natural gas industry, can fluctuate significantly, often in correlation with oil and natural gas prices, causing periodic shortages. Our operations are located in areas in which industry activity has increased rapidly beginning in the second half of 2016, and as a result, demand for such drilling rigs, equipment and personnel, as well as access to transportation, processing and refining facilities in these areas, has increased, as did the costs for those items. To the extent that industry activity remains high or increases in the future, any delay or inability to secure the personnel, equipment, power, services, resources and facilities access necessary for us to pursue our development activities could result in 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 cash flow and profitability. Furthermore, if we are unable to secure a sufficient number of drilling rigs at reasonable costs, we may not be able to drill all of our acreage before our leases expire.

We could experience periods of higher costs if commodity prices rise. These increases could reduce our profitability, cash flow and ability to complete development activities as planned.

Capital and operating costs typically rise during periods of increasing oil, natural gas and NGLs prices. These cost increases result from a variety of factors beyond our control, such as increases in the cost of electricity, steel and other raw materials that we and our vendors rely upon; increased demand for labor, services and materials as drilling activity increases; and increased taxes. Decreased levels of drilling activity in the oil and natural gas industry in recent periods have led to declining costs of some drilling equipment, materials and supplies. However, such costs may rise faster than increases in our revenue if commodity prices rise, thereby negatively impacting our profitability, cash flow and ability to complete development activities as scheduled and on budget. This impact may be magnified to the extent that our ability to participate in the commodity price increases is limited by our derivative activities.

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

Under the Energy Policy Act of 2005 (“EP Act of 2005”), the Federal Energy Regulatory Commission (“FERC”) has civil penalty authority under the Natural Gas Act of 1938 (the “NGA”) and the Natural Gas Policy

Act (“NGPA”) to impose penalties for current violations of up to $1,973,970 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. Additional rules and legislation pertaining to those and other matters may be considered or adopted by FERC from time to time. Failure to comply with those regulations in the future could subject us to civil penalty liability, as described in “Business—Regulation of the Oil and Natural Gas Industry”.

A change in the jurisdictional characterization of our natural gas assets by federal, state or local regulatory agencies or a change in policy by those agencies may result in increased regulation of our natural gas assets, which may cause our revenues to decline and operating expenses to increase.

Section 1(b) of the NGA exempts natural gas gathering facilities from the jurisdiction of FERC. We believe that our natural gas gathering pipelines meet the traditional test that FERC has used to determine whether a pipeline is a gathering pipeline and is, therefore, not subject to FERC jurisdiction. The distinction between FERC-regulated transmission services and federally unregulated gathering services, however, has been the subject of substantial litigation, and FERC determines whether facilities are gathering facilities on a case-by-case basis, so the classification and regulation of our gathering facilities is subject to change based on future determinations by FERC, the courts or Congress. If FERC were to consider the status of an individual facility and determine that the facility or services provided by it are not exempt from FERC regulation under the NGA and that the facility provides interstate service, the rates for, and terms and conditions of, services provided by such facility would be subject to regulation by FERC under the NGA or the NGPA. Such regulation could decrease revenue and increase operating costs. In addition, if any of our facilities were found to have provided services or otherwise operated in violation of the NGA or NGPA, this could result in the imposition of substantial civil penalties, as well as a requirement to disgorge revenues collected for such services in excess of the maximum rates established by FERC.

Our natural gas gathering pipelines are exempt from the jurisdiction of FERC under the NGA, but FERC regulation may indirectly impact gathering services. FERC’s policies and practices across the range of its oil and natural gas regulatory activities, including, for example, its policies on interstate open access transportation, ratemaking, capacity release, and market center promotion may indirectly affect intrastate markets. In recent years, FERC has pursued pro-competitive policies in its regulation of interstate oil and natural gas pipelines. However, we cannot assure you that FERC will continue to pursue this approach as it considers matters such as pipeline rates and rules and policies that may indirectly affect the natural gas gathering services.

Natural gas gathering may receive greater regulatory scrutiny at the state level; therefore, our natural gas gathering operations could be adversely affected should they become subject to the application of state regulation of rates and services. State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements and complaint-based rate regulation. Our gathering operations could also be subject to safety and operational regulations relating to the design, construction, testing, operation, replacement and maintenance of gathering facilities.

The rates of our regulated asset are subject to review and possible adjustment by federal and state regulators, which could adversely affect our revenues.

The FERC, pursuant to the ICA (as amended), the Energy Policy Act and rules and orders promulgated thereunder, regulates the tariff rates for our interstate common carrier crude oil and NGL pipeline. To be lawful under the ICA, interstate tariff rates, terms and conditions of service must be just and reasonable and not unduly discriminatory and must be on file with the FERC. In addition, pipelines may not confer any undue preference upon any shipper. Shippers may protest (and the FERC may investigate) the lawfulness of new or changed tariff rates. The FERC can suspend those tariff rates for up to seven months. It can also require refunds with interest of

amounts collected pursuant to rates that are ultimately found to be unlawful and prescribe new rates prospectively. The FERC and interested parties can also challenge tariff rates that have become final and effective. The FERC can also order new rates to take effect prospectively and order reparations for past rates that exceed the just and reasonable level up to two years prior to the date of a complaint. Due to the complexity of ratemaking, the lawfulness of any rate is never assured. A successful challenge of our rates could adversely affect our revenues.

The FERC uses prescribed rate methodologies for approving regulated tariff rate changes for interstate crude oil and NGL pipelines. The FERC’s indexing methodology currently allows a pipeline to increase its rates by a percentage linked to the PPI. However, a pipeline must file to lower its rates in any year in which the index is negative and its rates would be above the indexed rate ceiling. As an alternative to this indexing methodology, we may also choose to support our rates based on a cost-of-service methodology, or by obtaining advance approval to charge “market-based rates,” or by charging “settlement rates” agreed to by all affected shippers. These methodologies may limit our ability to set rates based on our actual costs or may delay the use of rates reflecting increased costs. In October 2016, the FERC issued an advance notice of proposed rulemaking seeking comment regarding potential modifications to its policies for evaluating oil pipeline indexed rate changes and to the reporting requirements. The FERC observed that some pipelines continue to obtain additional index rate increases despite reporting on Form No. 6 that their revenues exceed their costs. The FERC is proposing a new policy that would deny proposed index increases if a pipeline’s Form No. 6 reflects that revenues exceed by fifteen percent total cost of service for both of the prior two years or the proposed index increases exceed by five percent the annual cost changes reported by the pipeline. In addition, in December 2016, the FERC issued a Notice of Inquiry (“NOI”) in response to a remand from the U.S. Court of Appeals for the D.C. Circuit in United Airlines v. FERC, in which the court determined that FERC had not justified its conclusion that an oil pipeline organized as a partnership would not “double recover” its taxes under the current policy by both including a tax allowance in its cost-based rates and earning a return on equity calculated on a pre-tax basis. We cannot predict whether FERC will successfully justify its conclusion that there is no double recovery of taxes under these circumstances or whether FERC will modify its current policy on either income tax allowances or return on equity calculations.

The intrastate liquid pipeline transportation services we provide are subject to various state laws and regulations that apply to the rates we charge and the terms and conditions of the services we offer. Although state regulation typically is less onerous than FERC regulation, the rates we charge and the provision of our services may be subject to challenge.

Climate change laws and regulations restricting emissions of GHGs could result in increased operating costs and reduced demand for the oil and natural gas that we produce, while potential physical effects of climate change could disrupt our production and cause us to incur significant costs in preparing for or responding to those effects.

In response to findings that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment, the EPA has adopted regulations pursuant to the federal Clean Air Act that, among other things, require preconstruction and operating permits for certain large stationary sources. Facilities required to obtain preconstruction permits for their GHG emissions are also required to meet “best available control technology” standards that are being established by the states or, in some cases, by the EPA on a case-by-case basis. These regulatory requirements could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified sources. In addition, the EPA has adopted rules requiring the monitoring and reporting of GHG emissions from specified onshore and offshore oil and natural gas production sources in the United States on an annual basis, which include certain of our operations. Furthermore, in May 2016, the EPA finalized rules that establish new controls for emissions of methane from new, modified or reconstructed sources in the oil and natural gas source category, including production, processing, transmission and storage activities. The rules include first-time standards to address emissions of methane from equipment and processes across the source category, including hydraulically fractured oil and natural gas well completions. In

addition, the rules impose leak detection and repair requirements intended to address methane leaks known as “fugitive emissions” from equipment, such as valves, connectors, open-ended lines, pressure-relief devices, compressors, instruments and meters. Compliance with these rules will require enhanced record-keeping practices, the purchase of new equipment, such as optical gas imaging instruments to detect leaks, and increased frequency of maintenance and repair activities to address emissions leakage. The rules will also likely require additional personnel time to support these activities or the engagement of third-party contractors to assist with and verify compliance. The federal Bureau of Land Management also finalized similar rules regarding the control of methane emissions in November 2016 that apply to oil and natural gas exploration and development activities on public and tribal lands. The rules seek to minimize venting and flaring of emissions from storage tanks and other equipment, and also impose leak detection and repair requirements. These new and proposed rules could result in increased compliance costs on our operations.

While Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant legislative activity at the federal level in recent years. In the absence of such federal climate legislation, a number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions by means of cap and trade programs. These programs typically require major sources of GHG emissions to acquire and surrender emission allowances in return for emitting those GHGs. More recently, in December 2015, the United States and more than 190 other nations agreed to an international climate change agreement in Paris, France that calls for countries to set their own GHG emissions targets and be transparent about the measures each country will use to achieve its GHG emissions targets. The agreement came into effect in November 2016 and the effects of such agreement upon our operations and financial results are uncertain at this time.

Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any such future laws and regulations 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. Demand for our products may also be adversely affected by conservation plans and efforts undertaken in response to global climate change, including plans developed in connection with the recent Paris climate conference in December 2015, which came into effect in November 2016. Many governments also provide, or may in the future provide, tax advantages and other subsidies to support the use and development of alternative energy technologies. Substantial limitations on GHG emissions could also adversely affect demand for the oil and natural gas we produce and lower the value of our reserves.

Finally, increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events; if any such effects were to occur, they could have a material adverse effect on our operations. At this time, we have not developed a comprehensive plan to address the legal, economic, social or physical impacts of climate change on our operations.

Hydraulic fracturing is an important and common practice that is used to stimulate production of oil and/or natural gas from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, proppants and chemicals under pressure into targeted subsurface formations to fracture the surrounding rock and stimulate production. We regularly use hydraulic fracturing as part of our operations. Hydraulic fracturing is typically regulated by state oil and natural gas commissions, but federal agencies have asserted jurisdiction over certain aspects of the process. The EPA has asserted federal regulatory authority pursuant to the federal Safe Drinking Water Act (“SDWA”) over certain hydraulic fracturing activities involving the use of diesel fuels and published permitting guidance in February 2014 addressing the performance of such activities

using diesel fuels. The EPA has also taken the following actions: issued final regulations under the federal Clean Air Act establishing various performance standards, including standards for the capture of air emissions released during hydraulic fracturing, leak detection and permitting; issued an advanced notice of proposed rulemaking under the Toxic Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing; and, in June 2016, published an effluent limited guideline final rule prohibiting the discharge of wastewater from onshore unconventional oil and natural gas extraction facilities to publicly owned wastewater treatment plants. In addition, Congress has from time to time considered legislation to provide for federal regulation of hydraulic fracturing under the SDWA and to require disclosure of the chemicals used in the hydraulic fracturing process. It is unclear how any additional federal regulation of hydraulic fracturing activities may affect our operations.

Certain governmental reviews are either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. For example, in December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources. The final report concluded that that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources “under some circumstances,” noting that the following hydraulic fracturing water cycle activities and local or regional-scale factors are more likely than others to result in more frequent or more severe impacts: water withdrawals for fracturing in times or areas of low water availability; surface spills during the management of fracturing fluids, chemicals or produced water; injection of fracturing fluids into wells with inadequate mechanical integrity; injection of fracturing fluids directly into groundwater resources; discharge of inadequately treated fracturing wastewater to surface waters; and disposal or storage of fracturing wastewater in unlined pits.

At the state level, several states have adopted or are considering legal requirements that could impose more stringent permitting, disclosure and well construction requirements on hydraulic fracturing activities. Local governments also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular. In addition, in December 2016 the Oklahoma Corporation Commission (the “OCC”) announced that it had identified a link between hydraulic fracturing and seismic events in the SCOOP and STACK plays. The commission linked well completion operations to low-level seismic events that occurred in July 2016 in Blanchard, Oklahoma. In response to these events, the Commission has announced that it intends to issue “seismicity guidelines” for operators in the SCOOP and the STACK. At this time, we cannot predict what measures the OCC may require to reduce the risk of seismic events from hydraulic fracturing. If new or more stringent federal, state or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of development activities and perhaps even be precluded from drilling wells.

Federal and state legislative and regulatory initiatives relating to pipeline safety that require the use of new or more stringent safety controls or result in more stringent enforcement of applicable legal requirements could subject us to increased capital costs, operational delays and costs of operation.

Pursuant to the authority under the Natural Gas Pipeline Safety Act (“NGPSA”) and the Hazardous Liquid Pipeline Safety Act (“HLPSA”), as amended by the Pipeline Safety Improvement Act of 2002, the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006 and the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (“2011 Pipeline Safety Act”), the Pipeline and Hazardous Materials Safety Administration (“PHMSA”) has promulgated regulations requiring pipeline operators to develop and implement integrity management programs for certain gas and hazardous liquid pipelines that, in the event of a pipeline leak or rupture could affect “high consequence areas”, which are areas where a release could have the most significant adverse consequences, including high-population areas, certain drinking water sources and unusually sensitive ecological areas. These regulations require operators of covered pipelines to:

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perform ongoing assessments of pipeline integrity;

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identify and characterize applicable threats to pipeline segments that could impact a high consequence area;

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improve data collection, integration and analysis;

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repair and remediate the pipeline as necessary; and

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implement preventive and mitigating actions.

In addition, states have adopted regulations similar to existing PHMSA regulations for certain intrastate gas and hazardous liquid pipelines. At this time, we cannot predict the ultimate cost of compliance with applicable pipeline integrity management regulations, as the cost will vary significantly depending on the number and extent of any repairs found to be necessary as a result of pipeline integrity testing, but the results of these tests could cause us to incur significant and unanticipated capital and operating expenditures for repairs or upgrades deemed necessary to ensure the safe and reliable operation of our pipelines.

The 2011 Pipeline Safety Act requires increased safety measures for gas and hazardous liquids pipelines. Among other things, the 2011 Pipeline Safety Act directs the Secretary of Transportation to promulgate regulations relating to expanded integrity management requirements, automatic or remote-controlled valve use, excess flow valve use, leak detection system installation, testing to confirm the material strength of certain pipelines, and operator verification of records confirming the maximum allowable pressure of certain intrastate gas transmission pipelines. On June 22, 2016, President Obama signed into law new legislation entitled Protecting our Infrastructure of Pipelines and Enhancing Safety Act of 2016, or the PIPES Act. The PIPES Act reauthorizes PHMSA through 2019, and facilitates greater pipeline safety by providing PHMSA with emergency order authority, including authority to issue prohibitions and safety measures on owners and operators of gas or hazardous liquid pipeline facilities to address imminent hazards, without prior notice or an opportunity for a hearing, as well as enhanced release reporting requirements, requiring a review of both natural gas and hazardous liquid integrity management programs, and mandating the creation of a working group to consider the development of an information-sharing system related to integrity risk analyses. The PIPES Act also requires that PHMSA publish periodic updates on the status of those mandates outstanding from the 2011 Pipeline Safety Act, of which approximately half remain to be completed. The mandates yet to be acted upon include requiring certain shut-off valves on transmission lines, mapping all high consequence areas, and shortening the deadline for accident and incident notifications. Changes to pipeline safety laws by Congress and regulations by PHMSA or states that result in more stringent or costly safety standards could have a significant adverse effect on us and similarly situated midstream operators.

For example, in March of 2015, PHMSA finalized new rules applicable to gas and hazardous liquid pipelines that, among other changes, impose new post-construction inspections, welding, gas component pressure testing requirements, as well as requirements for calculating pressure reductions for immediate repairs on liquid pipelines. Also, in October 2015, PHMSA proposed new regulations for hazardous liquid pipelines that would significantly extend and expand the reach of certain PHMSA integrity management requirements (i.e., periodic assessments, repairs and leak detection), regardless of the pipeline’s proximity to a high consequence area. The proposal also requires new reporting requirements for certain unregulated pipelines, including all gathering lines. Also, in March 2016, pursuant to one of the requirements in 2011 Pipeline Safety Act, PHMSA published a proposed rulemaking that would expand integrity management requirements and impose new pressure testing requirements on currently regulated pipelines. The proposal would also significantly expand the regulation of gathering lines, subjecting previously unregulated pipelines to requirements regarding damage prevention, corrosion control, public education programs, maximum allowable operating pressure limits, and other requirements. More recently, in January 2017, PHMSA issued a final rule for hazardous liquid pipelines that significantly extends and expands the reach of certain PHMSA integrity management requirements (i.e., periodic assessments, leak detection and repairs), regardless of the pipeline’s proximity to a high consequence area. The final rule also imposes new reporting requirements for certain unregulated pipelines, including all hazardous

liquid gathering lines. However, this final rule remains subject to review and approval by the new administration pursuant to a memorandum issued by the White House to heads of federal agencies. It is unclear whether the final rule will be reissued and when it will be implemented. The safety enhancement requirements and other provisions of the 2011 Pipeline Safety Act as well as any implementation of PHMSA, rules thereunder could require us to install new or modified safety controls, pursue additional capital projects, or conduct maintenance programs on an accelerated basis, any or all of which tasks could result in our incurring increased operating costs that could have a material adverse effect on our results of operations or financial position.

Moreover, effective October 2013, PHMSA adopted new rules increasing the maximum administrative civil penalties for violation of the pipeline safety laws and regulations that occur after January 3, 2012 to $200,000 per violation per day and up to $2 million for a related series of violations. Effective August 1, 2016, to account for inflation, those maximum civil penalties were increased to $205,638 per violation per day, with a maximum of $2,056,380 for a related series of violations. Federal and state legislative and regulatory initiatives relating to pipeline safety that require the use of new or more stringent safety controls or result in more stringent enforcement of applicable legal requirements could subject us to increased capital costs, operational delays and costs of operation.

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

Large volumes of saltwater produced alongside our oil, natural gas and NGLs in connection with drilling and production operations are disposed of pursuant to permits issued 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 operating constraints or new monitoring and reporting requirements, owing to, among other things, concerns of the public or governmental authorities regarding such gathering or disposal activities.

Furthermore, in response to recent seismic events near underground disposal wells used for the disposal by injection of produced water resulting from oil and natural gas activities, federal and some state agencies are investigating whether such wells have caused increased seismic activity, and some states have restricted, suspended or shut down the use of such disposal wells. For example, in Oklahoma, the OCC has implemented a variety of measures including adopting the National Academy of Science’s “traffic light system” pursuant to which the agency reviews new disposal well applications for proximity to faults, seismicity in the area and other factors in determining whether such wells should be permitted, permitted only with special restrictions, or not permitted. The OCC also evaluates existing wells to assess their continued operation, or operation with restrictions, based on location relative to such faults, seismicity and other factors, with certain of such existing wells required to make frequent, or even daily, volume and pressure reports. In addition, the OCC has rules requiring operators of certain saltwater disposal wells in 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 wells within areas of interest where seismic incidents have occurred to restrict or suspend disposal well operations in an attempt to mitigate the occurrence of such incidents. For example, the OCC has established a 15 thousand square mile area of interest in the Arbuckle formation (the “Arbuckle”). Since 2013, the OCC has ordered the reduction of disposal volumes into the Arbuckle and directed the shut in of a number of wells in response to seismic activity in the Arbuckle. In addition, in January 2016, the Governor of Oklahoma announced a grant of $1.38 million in emergency funds to support earthquake research, which research is to be directed by the OCC and the Oklahoma Geological Survey. Most recently, in response to earthquakes in Cushing and Pawnee, Oklahoma, the OCC developed action plans in conjunction with the Oklahoma Geological Survey and the EPA. The plans were developed covering three areas, at six, 10 and 15 miles from the earthquake activity in both Cushing and Pawnee. Within six miles, all Arbuckle disposal wells must cease operations; within 10 miles, all Arbuckle disposal wells

must reduce volumes by 25 percent of their last 30-day average; and within 15 miles all disposal wells are limited to their last 30-day average. These actions are in addition to any previous orders to shut in wells. In the Pawnee area, the action plan covers a total of 38 Arbuckle disposal wells under OCC jurisdiction and 26 Arbuckle disposal wells under EPA jurisdiction, and in the Cushing area the plan covers a total of 58 Arbuckle disposal wells. Our saltwater disposal wells in Oklahoma are not impacted by these current restrictions. Local residents have also recently filed lawsuits against operators in these areas for damages resulting from the increased seismic activity.

Additionally, the Governor of Kansas has established a task force composed of various administrative agencies to study and develop an action plan for addressing seismic activity in the state. The task force issued a recommended Seismic Action Plan calling for enhanced seismic monitoring and the development of a seismic response plan, and in November 2014, the Governor of Kansas announced a plan to enhance seismic monitoring in the state. In March 2015, the Kansas Corporation Commission (the “KCC”) issued its Order Reducing Saltwater Injection Rates (the “2015 Order”). The 2015 Order identified five areas of heightened seismic concern in Harper and Sumner Counties and created a timeframe over which the maximum of 8,000 barrels of saltwater injection daily into each well, including one of our saltwater disposal wells. Further, any injection well drilled deeper than the Arbuckle was required to be plugged back in a manner approved by the KCC. On September 14, 2015, the KCC extended the 2015 Order until March 13, 2016. Most recently, in August 2016, the KCC staff approved an order expanding the areas of heightened seismic concern, which includes an additional schedule of volume reductions to 16,000 barrels of saltwater for Arbuckle disposal wells not previously identified in the 2015 Order, including all of our remaining saltwater disposal wells. To date, these restrictions have not had a material impact on our business.

Evaluation of seismic incidents and whether or to what extent those events are induced by the injection of saltwater into disposal wells continues to evolve, as governmental authorities consider new and/or past seismic incidents in areas where salt water disposal activities occur or are proposed to be performed. The adoption of any new laws, regulations, directives, or orders resulting from litigation that restrict our ability to dispose of saltwater generated by production and development activities, whether by plugging back the depths of disposal wells, reducing the volume of salt water disposed in such wells, restricting disposal well locations or otherwise, or by requiring us to shut down disposal wells, which could negatively affect the economic lives of some of our properties.

The adoption and implementation of any new laws, regulations or legal directives that restrict our ability to dispose of saltwater, by limiting volumes, disposal rates, disposal well locations or otherwise, or requiring us to shut down disposal wells, could require us or the operators of wells in which we have has interests to shut in a substantial number of such wells and, accordingly, could materially and adversely affect our business, financial condition and results of operations.

Competition in the oil and natural gas industry is intense, making it difficult for us to acquire properties, market oil or natural gas and secure trained personnel.

Our ability to acquire additional prospects and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment for acquiring properties, marketing oil and natural gas and securing trained personnel. Also, there is substantial competition for capital available for investment in the oil and natural gas industry. Many of our competitors possess and employ financial and technical personnel resources substantially greater than ours. Those companies may be able to pay more for productive properties and exploratory prospects and to evaluate, bid for and purchase a greater number of properties and prospects than our financial or technical personnel resources permit. In addition, other companies may be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer. The cost to attract and retain qualified personnel may increase substantially in the future. We may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves, marketing hydrocarbons, attracting and retaining quality personnel and raising additional capital, which could have a material adverse effect on our business.

The loss of senior management or technical personnel could adversely affect operations.

We depend on the services of our senior management and technical personnel. We do not maintain, nor do we plan to obtain, any insurance against the loss of any of these individuals. The loss of the services of our senior management or technical personnel could have a material adverse effect on our business, financial condition and results of operations.

Increases in interest rates could adversely affect our business.

Our business and operating results can be harmed by factors such as the availability, terms of and cost of capital, increases in interest rates or a reduction in credit rating. These changes could cause our cost of doing business to increase, limit our ability to pursue acquisition opportunities, reduce cash flow used for drilling and place us at a competitive disadvantage. For example, as of December 31, 2016, outstanding borrowings subject to variable interest rates were approximately $350.0 million, and a 1.0% increase in interest rates would result in an increase in annual interest expense of approximately $3.5 million, assuming the $350.0 million of debt was outstanding for the full year. Recent and continuing disruptions and volatility in the global financial markets may lead to a contraction in credit availability impacting our ability to finance our operations. We require continued access to capital. A significant reduction in cash flows from operations or the availability of credit could materially and adversely affect our ability to achieve our planned growth and operating results.

The present U.S. federal and state income tax laws affecting oil and natural gas exploration, development, and extraction may be modified by administrative, legislative or judicial interpretation at any time. Future legislation may result in the elimination of certain U.S. federal income tax deductions currently available with respect to oil and natural gas exploration and development and may impose new or increased taxes on oil and natural gas extraction.

The present U.S. federal and state income tax laws affecting oil and natural gas exploration, development, and extraction may be modified by administrative, legislative or judicial interpretation at any time. Potential legislation, if enacted into law, could make significant changes to such laws, including the elimination of certain key U.S. federal income tax incentives currently available to oil and natural gas exploration and production companies. These changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain U.S. production activities and (iv) an extension of the amortization period for certain geological and geophysical expenditures. Additionally, future legislation could be enacted that increases the taxes imposed on oil and natural gas extraction. The passage or adoption of these changes, or similar changes, could eliminate or postpone certain tax deductions that are currently available with respect to oil and natural gas exploration and development or could result in increased operating costs. We are unable to predict whether any of these changes or other proposals will be enacted, or whether the current Administration will propose new changes to existing laws, including as a result of fundamental tax reform. Any such changes could adversely affect our business, financial condition and results of operations.

Our use of seismic data is subject to interpretation and may not accurately identify the presence of oil and natural gas, which could adversely affect the results of our drilling operations.

Even when properly used and interpreted, seismic data and visualization techniques are only tools used to assist geoscientists in identifying subsurface structures and hydrocarbon indicators and do not enable the interpreter to know whether hydrocarbons are, in fact, present in those structures. As a result, our drilling activities may not be successful or economical. In addition, the use of advanced technologies, such as 3D seismic data, requires greater pre-drilling expenditures than traditional drilling strategies, and we could incur losses as a result of such expenditures.

Restrictions on drilling activities intended to protect certain species of wildlife may adversely affect our ability to conduct drilling activities in areas where we operate.

Oil and natural gas operations in our operating areas may be adversely affected by seasonal or permanent restrictions on drilling activities designed to protect various wildlife. Seasonal restrictions may limit our ability to operate in protected areas and can intensify competition for drilling rigs, oilfield equipment, services, supplies and qualified personnel, which may lead to periodic shortages when drilling is allowed. These constraints and the resulting shortages or high costs could delay our operations or materially increase our operating and capital costs. Permanent restrictions imposed to protect endangered species could prohibit drilling in certain areas or require the implementation of expensive mitigation measures. The designation of previously unprotected species in areas where we operate as threatened or endangered could cause us to incur increased costs arising from species protection measures or could result in limitations on our activities that could have a material and adverse impact on our ability to develop and produce our reserves.

Laws regulating the derivatives market could adversely affect our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business.

The Dodd-Frank Act established federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market. Under the Dodd-Frank Act, the Commodity Futures Trading Commission (“CFTC”) and the SEC have promulgated rules, and are in the process of promulgating other rules, required to implement the derivatives regulatory provisions of the Dodd-Frank Act. Among the rules currently proposed for adoption by the CFTC are proposed rules that would place limits on positions in certain core futures and equivalent swaps contracts for or linked to certain physical commodities, subject to exceptions for certain bona fide hedging transactions. These new position limit rules are not yet final, and the impact of the final position rules on us is uncertain at this time.

The Dodd-Frank Act also made the clearing of swaps over a derivatives clearing organization mandatory and the execution of cleared swaps over a board of trade or swap execution facility mandatory, subject to certain exemptions. The CFTC has designated certain interest rate swaps and credit default swaps for mandatory clearing. The CFTC has not yet proposed rules designating any other classes of swaps, including physical commodity swaps, for mandatory clearing. Although we expect to qualify for the exception from mandatory clearing available to commercial end-users of swaps, if we were to have to clear any swap we enter, we might not have the same flexibility we have with the bilateral swaps we now enter and would have to post margin with the derivatives clearing organization for such cleared swaps, which could adversely our ability to execute hedges to reduce risk and protect our cash flow, could adversely affect our liquidity and could reduce cash available to us for capital expenditures.

Certain banking regulators and the CFTC have recently adopted final rules establishing minimum margin requirements for uncleared swaps. Although we expect to qualify for exemption from such margin requirements available to users of swaps who are non-financial end-users entering into uncleared swaps to hedge their commercial risks with respect to any swaps we enter for such purpose, the application of such requirements to other market participants, such as swap dealers, may change the cost and availability of the swaps that we use for hedging. If we do not qualify for an exemption from the margin rules, we could have to post initial and variation margin with the counterparties to our swaps, which could impact our liquidity and reduce cash available to us for capital expenditures, therefore reducing our ability to execute hedges to reduce risk and protect our cash flow.

The full impact of the Dodd-Frank Act’s swap regulatory provisions and the related rules of the CFTC and SEC on our business will not be known until all of the rules to be adopted under the Dodd-Frank Act have been adopted and fully implemented and the market for derivatives contracts has adjusted. The Dodd-Frank Act, the existing rules and any new rules could significantly increase the cost of derivative contracts, materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, and

reduce our ability to monetize or restructure our existing derivative contracts. If we reduce our use of derivatives as a result of the Dodd-Frank Act’s swap regulatory provisions and the related rules, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the Dodd-Frank Act’s swap regulatory provisions were intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the Dodd-Frank Act and implementing rules is to lower commodity prices. Any of these consequences could have a material and adverse effect on us and our financial condition.

The European Union and other non-U.S. jurisdictions have implemented or may implement regulations with respect to the derivatives market. If we enter into swaps with counterparties based in foreign jurisdictions, we may become subject to such regulations, which could have adverse effects on our operations similar to the possible effects on our operations of the Dodd-Frank Act’s swap regulatory provisions and the rules of the CFTC, SEC and U.S. banking regulators.

The standardized measure of our estimated reserves is not an accurate estimate of the current fair value of our estimated reserves.

Standardized measure is a reporting convention that provides a common basis for comparing oil and natural gas companies subject to the rules and regulations of the SEC. Standardized measure requires the use of specific pricing as required by the SEC as well as operating and development costs prevailing as of the date of computation. Consequently, it may not reflect the prices ordinarily received or that will be received for oil and natural gas production because of varying market conditions, nor may it reflect the actual costs that will be required to produce or develop the oil and natural gas properties. In addition, our predecessor generally passed through its taxable income to its owners for income tax purposes and was not subject to U.S. federal, state or local income taxes other than franchise tax in the State of Texas. Accordingly, our standardized measure does not provide for U.S. federal, state or local income taxes other than franchise tax in the State of Texas. However, following our corporate reorganization, we will be subject to U.S. federal, state and local income taxes. Accordingly, estimates included herein of future net cash flow may be materially different from the future net cash flows that are ultimately received. Therefore, the standardized measure of our estimated reserves included in this prospectus should not be construed as accurate estimates of the current fair value of our proved reserves.

Our business is difficult to evaluate because we have a limited operating history and we are susceptible to the potential difficulties associated with rapid growth and expansion.

Our predecessor, Tapstone Energy, LLC, was formed in 2013. As a result, there is only limited historical financial and operating information available upon which to base your evaluation of our performance.

In addition, we have grown rapidly over the last several years. Our management believes that our future success depends on our ability to manage the rapid 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. The historical financial information herein is not necessarily indicative of the results that may be realized in the future. In addition, our operating history is limited and the results from our current producing wells are not necessarily indicative of success from our future drilling operations.

We may not be able to keep pace with technological developments in our 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 may be forced by competitive pressures 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 that may in the future allow them to implement new technologies before we can. We may not be able to respond to these competitive pressures or 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, our business, financial condition or results of operations could be materially and adversely affected.

Negative public perception regarding us and/or our industry could have an adverse effect on our operations.

Negative public perception regarding us and/or our industry resulting from, among other things, concerns raised by advocacy groups about hydraulic fracturing, oil spills, seismic activity and explosions of natural gas transmission lines may lead to increased regulatory scrutiny, which may, in turn, lead to new state and federal safety and environmental laws, regulations, guidelines and enforcement interpretations. These actions may cause operational delays or restrictions, increased operating costs, additional regulatory burdens and increased risk of litigation. Moreover, governmental authorities exercise considerable discretion in the timing and scope of permit issuance and the public may engage in the permitting process, including through intervention in the courts. Negative public perception could cause the permits we need to conduct our operations to be withheld, delayed, or burdened by requirements that restrict our ability to profitably conduct our business.

Our business could be negatively affected by security threats, including cybersecurity threats, and other disruptions.

As an oil and natural gas producer, we face various security threats, including cybersecurity threats to gain unauthorized access to sensitive information or to render data or systems unusable; threats to the security of our facilities and infrastructure or third-party facilities and infrastructure, such as processing plants and pipelines; and threats from terrorist acts. The potential for such security threats has subjected our operations to increased risks that could have a material adverse effect on our business. In particular, our implementation of various procedures and controls to monitor and mitigate security threats and to increase security for our information, facilities and infrastructure may result in increased capital and operating costs. Moreover, there can be no assurance that such procedures and controls will be sufficient to prevent security breaches from occurring. If any of these security breaches were to occur, they could lead to losses of sensitive information, critical infrastructure or capabilities essential to our operations and could have a material adverse effect on our reputation, financial position, results of operations or cash flows. Cybersecurity attacks in particular are becoming more sophisticated and include, but are not limited to, malicious software, attempts to gain unauthorized access to data and systems, and other electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise protected information, and corruption of data. These events could lead to financial losses from remedial actions, loss of business or potential liability.

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. In particular, our business relies heavily on a methodology available in Oklahoma known as “statutory forced pooling,” which refers to the ability of a holder of an oil and natural gas interest in a particular prospective spacing unit to apply to the OCC for an order forcing all other holders of oil and natural gas interests in such spacing unit into a common pool for purposes of developing that spacing unit. Changes in the legal and regulatory environment governing our industry,

particularly any changes to Oklahoma statutory forced pooling procedures that make forced pooling more difficult to accomplish, could result in increased compliance costs and adversely affect our business and results of our operations.

We may be involved in legal proceedings that could result in substantial liabilities.

Like many oil and natural gas companies, we are from time to time involved in various legal and other proceedings, such as title, royalty or contractual disputes, regulatory compliance matters and personal injury or property damage matters, in the ordinary course of our business. In addition, as noted above, some groups in Oklahoma have begun filing lawsuits against operators as a result of increased seismic events. 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 liability, 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.

Risks Related to this Offering and Our Common Stock

The requirements of being a public company, including compliance with the reporting requirements of the Exchange Act, and the requirements of Sarbanes-Oxley, may strain our resources, increase our costs and distract management, and we may be unable to comply with these requirements in a timely or cost-effective manner.

As a public company, we will need to comply with new laws, regulations and requirements, certain corporate governance provisions of Sarbanes-Oxley, related regulations of the SEC and the requirements of the NYSE, with which we are not required to comply as a private company. Complying with these statutes, regulations and requirements will occupy a significant amount of time of our board of directors and management and will significantly increase our costs and expenses. We will need to:

•

institute a more comprehensive compliance function;

•

comply with rules promulgated by the NYSE;

•

continue to prepare and distribute periodic public reports in compliance with our obligations under the federal securities laws;

•

establish new internal policies, such as those relating to insider trading; and

•

involve and retain to a greater degree outside counsel and accountants in the above activities.

Furthermore, while we generally must comply with Section 404 of Sarbanes Oxley for our fiscal year ending December 31, 2017, we are not required to have our independent registered public accounting firm attest to the effectiveness of our internal controls until our first annual report subsequent to our ceasing to be an “emerging growth company” within the meaning of Section 2(a)(19) of the Securities Act. Accordingly, we may not be required to have our independent registered public accounting firm attest to the effectiveness of our internal controls until as late as our annual report for the fiscal year ending December 31, 2022. Once it is required to do so, our independent registered public accounting firm may issue a report that is adverse in the event it is not satisfied with the level at which our controls are documented, designed, operated or reviewed. Compliance with these requirements may strain our resources, increase our costs and distract management, and we may be unable to comply with these requirements in a timely or cost-effective manner.

In addition, we expect that being a public company subject to these rules and regulations may make it more difficult and more expensive for us to obtain director and officer liability insurance and we may be required to accept reduced policy limits and coverage or incur substantially higher costs to obtain the same or similar coverage. As a result, it may be more difficult for us to attract and retain qualified individuals to serve on our board of directors or as executive officers. We are currently evaluating these rules, and we cannot predict or estimate the amount of additional costs we may incur or the timing of such costs.

If we fail to develop or maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud. As a result, current and potential stockholders could lose confidence in our financial reporting, which would harm our business and the trading price of our common stock.

Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and operate successfully as a public company. If we cannot provide reliable financial reports or prevent fraud, our reputation and operating results would be harmed. We cannot be certain that our efforts to develop and maintain our internal controls will be successful, that we will be able to maintain adequate controls over our financial processes and reporting in the future or that we will be able to comply with our obligations under Section 404 of Sarbanes Oxley. Any failure to develop or maintain effective internal controls, or difficulties encountered in implementing or improving our internal controls, could harm our operating results or cause us to fail to meet our reporting obligations. Ineffective internal controls could also cause investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our common stock.

The initial public offering price of our common stock may not be indicative of the market price of our common stock after this offering. In addition, an active, liquid and orderly trading market for our common stock may not develop or be maintained, and our stock price may be volatile.

Prior to this offering, our common stock was not traded on any market. An active, liquid and orderly trading market for our common stock may not develop or be maintained after this offering. Active, liquid and orderly trading markets usually result in less price volatility and more efficiency in carrying out investors’ purchase and sale orders. The market price of our common stock could vary significantly as a result of a number of factors, some of which are beyond our control. In the event of a drop in the market price of our common stock, you could lose a substantial part or all of your investment in our common stock. The initial public offering price will be negotiated between us, the selling stockholder and the representatives of the underwriters, based on numerous factors which we discuss in “Underwriting (Conflicts of Interest)”, and may not be indicative of the market price of our common stock after this offering. Consequently, you may not be able to sell shares of our common stock at prices equal to or greater than the price paid by you in this offering.

The following factors could affect our stock price:

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our operating and financial performance and drilling locations, including reserve estimates;

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quarterly variations in the rate of growth of our financial indicators, such as net income per share, net income, revenues and Adjusted EBITDA;

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the public reaction to our press releases, our other public announcements and our filings with the SEC;

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strategic actions by our competitors;

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changes in revenue or earnings estimates, or changes in recommendations or withdrawal of research coverage, by equity research analysts;

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speculation in the press or investment community;

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the failure of research analysts to cover our common stock;

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sales of our common stock by us or the selling stockholder or the perception that such sales may occur;

•

changes in accounting principles, policies, guidance, interpretations or standards;

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additions or departures of key management personnel;

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actions by our stockholders;

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general market conditions, including fluctuations in commodity prices;

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domestic and international economic, legal and regulatory factors unrelated to our performance; and

•

the realization of any risks described under this “Risk Factors” section.

The stock markets in general have experienced extreme volatility that has often been unrelated to the operating performance of particular companies. These broad market fluctuations may adversely affect the trading price of our common stock. Securities class action litigation has often been instituted against companies following periods of volatility in the overall market and in the market price of a company’s securities. Such litigation, if instituted against us, could result in very substantial costs, divert our management’s attention and resources and harm our business, operating results and financial condition.

GSO will have the ability to direct the voting of a majority of our common stock, and its interests may conflict with those of our other stockholders.

Upon completion of this offering, GSO will beneficially own approximately % of our outstanding common stock (or approximately % if the underwriters’ option to purchase additional shares is exercised in full). As a result, GSO will be able to control matters requiring stockholder approval, including the election of directors, changes to our organizational documents and significant corporate transactions. This concentration of ownership makes it unlikely that any other holder or group of holders of our common stock will be able to affect the way we are managed or the direction of our business. The interests of GSO with respect to matters potentially or actually involving or affecting us, such as future acquisitions, financings and other corporate opportunities and attempts to acquire us, may conflict with the interests of our other stockholders. Given this concentrated ownership, GSO would have to approve any potential acquisition of us. In addition, certain of our directors and director nominees are currently employees of or otherwise provide services to GSO. These directors’ duties as employees of or service providers to GSO may conflict with their duties as our directors, and the resolution of these conflicts may not always be in our or your best interest. Furthermore, in connection with this offering, we will enter into a stockholders’ agreement with GSO. Among other things, the stockholders’ agreement will provide GSO with the right to designate a certain number of nominees to our board of directors so long as it and its affiliates collectively beneficially own at least 5% of the outstanding shares of our common stock. Please read “Certain Relationships and Related Party Transactions—Stockholders’ Agreement”. The existence of a significant stockholder and the stockholders’ agreement may have the effect of deterring hostile takeovers, delaying or preventing changes in control or changes in management or limiting the ability of our other stockholders to approve transactions that they may deem to be in our best interests. Moreover, GSO’s concentration of stock ownership may also adversely affect the trading price of our common stock to the extent investors perceive a disadvantage in owning stock of a company with a significant stockholder.

Certain of our directors and director nominees have significant duties with, and spend significant time serving, entities that may compete with us in seeking acquisitions and business opportunities and, accordingly, may have conflicts of interest in allocating time or pursuing business opportunities.

Certain of our directors and director nominees, who are responsible for managing the direction of our operations and acquisition activities, hold positions of responsibility with other entities (including affiliates of

GSO) that are in the business of identifying and acquiring oil and natural gas properties. For example, two of our directors, Messrs. Scott and Horn, and one of our director nominees, Mr. Posnick, serve as Senior Managing Directors of GSO, which is in the business of loaning money to and investing in oil and natural gas companies that seek to acquire oil and natural gas properties. In addition, another of our director nominees, Mr. Baker, is a practicing attorney whose primary client has been GSO since 2013. The existing positions and commercial relationships held by these directors and director nominees may give rise to fiduciary or other duties that are in conflict with the duties they owe to us. These directors and director nominees may become aware of business opportunities that may be appropriate for presentation to us as well as to the other entities with which they are or may become affiliated. Due to these existing and potential future affiliations, they may present potential business opportunities to other entities prior to presenting them to us, which could cause additional conflicts of interest. They may also decide that certain opportunities are more appropriate for other entities with which they are affiliated, and as a result, they may elect not to present those opportunities to us. These conflicts may not be resolved in our favor. For additional discussion of our management’s business affiliations and the potential conflicts of interest of which our stockholders should be aware, please read “Certain Relationships and Related Party Transactions”.

GSO is not limited in its ability to compete with us, and the corporate opportunity provisions in our amended and restated certificate of incorporation could enable GSO to benefit from corporate opportunities that might otherwise be available to us.

Our governing documents will provide that GSO (including portfolio investments of GSO) is not restricted from owning assets or engaging in businesses that compete directly or indirectly with us. In particular, subject to the limitations of applicable law, our amended and restated certificate of incorporation will, among other things:

•

permit GSO and our non-employee directors to conduct business that competes with us and to make investments in any kind of property in which we may make investments; and

GSO may become aware, from time to time, of certain business opportunities (including acquisition opportunities) and may direct such opportunities to other businesses in which they have invested, in which case we may not become aware of or otherwise have the ability to pursue such opportunities. Further, such businesses may choose to compete with us for these opportunities, possibly causing these opportunities to not be available to us or causing them to be more expensive for us to pursue. In addition, GSO may dispose of oil and natural gas properties or other assets in the future, without any obligation to offer us the opportunity to purchase any of those assets.

GSO is an established participant in the oil and natural gas industry and has resources greater than ours, which may make it more difficult for us to compete with such person with respect to commercial activities as well as for potential acquisitions. We cannot assure you that any conflicts that may arise between us and our stockholders, on the one hand, and GSO, on the other hand, will be resolved in our favor. As a result, competition from GSO could adversely impact our results of operations.

Our amended and restated certificate of incorporation and amended and restated bylaws, as well as Delaware law, will contain provisions that could discourage acquisition bids or merger proposals, which may adversely affect the market price of our common stock.

Our amended and restated certificate of incorporation will authorize our board of directors to issue preferred stock without stockholder approval. If our board of directors elects to issue preferred stock, it could be more difficult for a third-party to acquire us. In addition, some provisions of our amended and restated certificate of incorporation and amended and restated bylaws could make it more difficult for a third-party to acquire control of us, even if the change of control would be beneficial to our stockholders, including:

•

limitations on the removal of directors;

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our classified board of directors, under which a director only comes up for election once every three years;

•

limitations on the ability of our stockholders to call special meetings;

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establishing advance notice provisions for stockholder proposals and nominations for elections to the board of directors to be acted upon at meetings of stockholders;

•

providing that the board of directors is expressly authorized to adopt, or to alter or repeal our amended and restated bylaws; and

•

establishing advance notice and certain information requirements for nominations for election to our board of directors or for proposing matters that can be acted upon by stockholders at stockholder meetings.

Our amended and restated certificate of incorporation will designate the Court of Chancery of the State of Delaware as the sole and exclusive forum for certain types of actions and proceedings that may be initiated by our stockholders, which could limit our stockholders’ ability to obtain a favorable judicial forum for disputes with us or our directors, officers, employees or agents.

Our amended and restated certificate of incorporation will provide that, unless we consent in writing to the selection of an alternative forum, the Court of Chancery of the State of Delaware will, to the fullest extent permitted by applicable law, be the sole and exclusive forum for (i) any derivative action or proceeding brought on our behalf, (ii) any action asserting a claim of breach of a fiduciary duty owed by any of our directors, officers, employees or agents to us or our stockholders, (iii) any action asserting a claim arising pursuant to any provision of the Delaware General Corporation Law (the “DGCL”), our amended and restated certificate of incorporation or our amended and restated bylaws or (iv) any action asserting a claim against us that is governed by the internal affairs doctrine. Any person or entity purchasing or otherwise acquiring any interest in shares of our capital stock will be deemed to have notice of, and consented to, the provisions of our amended and restated certificate of incorporation described in the preceding sentence. This choice of forum provision may limit a stockholder’s ability to bring a claim in a judicial forum that it finds favorable for disputes with us or our directors, officers, employees or agents, which may discourage such lawsuits against us and such persons. Alternatively, if a court were to find these provisions of our amended and restated certificate of incorporation inapplicable to, or unenforceable in respect of, one or more of the specified types of actions or proceedings, we may incur additional costs associated with resolving such matters in other jurisdictions, which could adversely affect our business, financial condition or results of operations.

Investors in this offering will experience immediate and substantial dilution of $ per share.

Based on an assumed initial public offering price of $ per share (the midpoint of the range set forth on the cover of this prospectus), purchasers of our common stock in this offering will experience an immediate

and substantial dilution of $ per share in the as adjusted net tangible book value per share of common stock from the initial public offering price, and our as adjusted net tangible book value as of December 31, 2016, after giving effect to this offering would be $ per share. This dilution is due in large part to earlier investors having paid substantially less than the initial public offering price when they purchased their shares. Please read “Dilution”.

We do not intend to pay cash dividends on our common stock, and our credit agreement places certain restrictions on our ability to do so. Consequently, your only opportunity to achieve a return on your investment is if the price of our common stock appreciates.

We do not plan to declare cash dividends on shares of our common stock in the foreseeable future. Additionally, our credit agreement places certain restrictions on our ability to pay cash dividends. Consequently, your only opportunity to achieve a return on your investment in us will be if you sell your common stock at a price greater than you paid for it. There is no guarantee that the price of our common stock that will prevail in the market will ever exceed the price that you pay in this offering.

Future sales of our common stock in the public market, or the perception that such sales may occur, could reduce our stock price, and any additional capital raised by us through the sale of equity or convertible securities may dilute your ownership in us.

We may sell additional shares of common stock in subsequent public offerings. We may also issue additional shares of common stock or securities convertible into shares of our common stock. After the completion of this offering, we will have outstanding shares of common stock. This number includes shares that we are selling in this offering and shares that the selling stockholder may sell in this offering if the underwriters’ option to purchase additional shares is fully exercised, which may be resold immediately in the public market. Following the completion of this offering, and assuming full exercise of the underwriters’ over-allotment option, GSO will own shares of our common stock, or approximately % of our total outstanding shares, all of which are restricted from immediate resale under the federal securities laws and are subject to the lock-up agreements between them and the underwriters described in “Underwriting (Conflicts of Interest)”, but may be sold into the market in the future. GSO will be party to a registration rights agreement, which will require us to effect the registration of its shares in certain circumstances no earlier than the expiration of the lock-up period contained in the underwriting agreement entered into in connection with this offering.

In connection with this offering, we intend to file a registration statement with the SEC on Form S-8 providing for the registration of shares of our common stock issued or reserved for issuance under our Long-Term Incentive Plan. Subject to the satisfaction of vesting conditions, the expiration of lock-up agreements and the requirements of Rule 144, shares registered under the registration statement on Form S-8 may be made available for resale immediately in the public market without restriction.

We cannot predict the size of future issuances of our common stock or securities convertible into common stock or the effect, if any, that future issuances and sales of shares of our common stock will have on the market price of our common stock. Sales of substantial amounts of our common stock (including shares issued in connection with an acquisition), or the perception that such sales could occur, may adversely affect prevailing market prices of our common stock.

The underwriters of this offering may waive or release parties to the lock-up agreements entered into in connection with this offering, which could adversely affect the price of our common stock.

We, all of our directors, director nominees and executive officers and the selling stockholder have entered or will enter into lock-up agreements pursuant to which we and they will be subject to certain restrictions with respect to the sale or other disposition of our common stock for a period of 180 days following the date of

this prospectus. Merrill Lynch, Pierce, Fenner & Smith Incorporated and Citigroup Global Markets Inc., at any time and, except in the case of directors, director nominees and executive officers, without notice, may release all or any portion of the common stock subject to the foregoing lock-up agreements. Please read “Underwriting (Conflicts of Interest)” for more information on these agreements. If the restrictions under the lock-up agreements are waived, then the common stock, subject to compliance with the Securities Act or exceptions therefrom, will be available for sale into the public markets, which could cause the market price of our common stock to decline and impair our ability to raise capital.

We may issue preferred stock the terms of which could adversely affect the voting power or value of our common stock.

Our amended and restated certificate of incorporation will authorize us to issue, without the approval of our stockholders, one or more classes or series of preferred stock having such designations, preferences, limitations and relative rights, including preferences over our common stock respecting dividends and distributions, as our board of directors may determine. The terms of one or more classes or series of preferred stock could adversely impact the voting power or value of our common stock. For example, we might grant holders of preferred stock the right to elect some number of our directors in all events or on the happening of specified events or the right to veto specified transactions. Similarly, the repurchase or redemption rights or liquidation preferences we might assign to holders of preferred stock could affect the residual value of the common stock.

We expect to be a “controlled company” within the meaning of the NYSE rules and, as a result, will qualify for and intend to rely on exemptions from certain corporate governance requirements.

Upon completion of this offering, GSO will beneficially control a majority of the combined voting power of all classes of our outstanding voting stock. As a result, we expect to be a controlled company within the meaning of the NYSE corporate governance standards. Under the NYSE rules, a company of which more than 50% of the voting power is held by another person or group of persons acting together is a controlled company and may elect not to comply with certain NYSE corporate governance requirements, including the requirements that:

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a majority of the board of directors consist of independent directors;

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the nominating and governance committee be composed entirely of independent directors with a written charter addressing the committee’s purpose and responsibilities;

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the compensation committee be composed entirely of independent directors with a written charter addressing the committee’s purpose and responsibilities; and

•

there be an annual performance evaluation of the nominating and governance and compensation committees.

These requirements will not apply to us as long as we remain a controlled company. Following this offering, we intend to utilize some or all of these exemptions. Accordingly, you may not have the same protections afforded to stockholders of companies that are subject to all of the corporate governance requirements of the NYSE. Please read “Management”.

For as long as we are an emerging growth company, we will not be required to comply with certain reporting requirements, including those relating to accounting standards and disclosure about our executive compensation, that apply to other public companies.

In April 2012, President Obama signed into law the JOBS Act. 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 Sarbanes-Oxley, (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 disclosure 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 in a fiscal year, have more than $700.0 million in market value of our common stock held by non-affiliates, or issue more than $1.0 billion of non-convertible debt over a three-year period.

To the extent that we rely on any of the exemptions available to emerging growth companies, you will receive less information about our executive compensation and internal control over financial reporting than issuers that are not emerging growth companies. If some investors find our common stock to be less attractive as a result, there may be a less active trading market for our common stock and our stock price may be more volatile.

If securities or industry analysts do not publish research or reports about our business, if they adversely change their recommendations regarding our common stock or if our operating results do not meet their expectations, our stock price could decline.

The trading market for our common stock will be influenced by the research and reports that industry or securities analysts publish about us or our business. If one or more of these analysts cease coverage of our company or fail to publish reports on us regularly, we could lose visibility in the financial markets, which in turn could cause our stock price or trading volume to decline. Moreover, if one or more of the analysts who cover our company downgrades our common stock or if our operating results do not meet their expectations, our stock price could decline.

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

The information in this prospectus includes “forward-looking statements”. All statements, other than statements of historical fact included in this prospectus, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this prospectus, the words “could”, “believe”, “anticipate”, “intend”, “estimate”, “expect”, “project” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on management’s current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements described under the heading “Risk Factors” and the other information included in this prospectus.

Forward-looking statements may include statements about:

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our business strategy;

•

our reserves;

•

our drilling prospects, inventories, projects and programs;

•

our ability to replace the reserves we produce through drilling and property acquisitions;

•

our financial strategy, liquidity and capital required for our drilling program;

•

our realized oil, natural gas and NGLs prices;

•

the timing and amount of our future production of oil, natural gas and NGLs;

•

our hedging strategy and results;

•

our future drilling plans;

•

our competition and government regulations;

•

our ability to obtain permits and governmental approvals;

•

our pending legal or environmental matters;

•

our marketing of oil, natural gas and NGLs;

•

our leasehold or business acquisitions;

•

our costs of developing our properties;

•

general economic conditions;

•

credit markets;

•

uncertainty regarding our future operating results; and

•

our plans, objectives, expectations and intentions contained in this prospectus that are not historical.

We caution you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control, incident to the development, production, gathering and sale of oil, natural gas and NGLs. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures and the other risks described under “Risk Factors” and elsewhere in this prospectus.

Reserve engineering is a process of estimating underground accumulations of hydrocarbons that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reserve engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions could impact our strategy and change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of oil, natural gas and NGLs that are ultimately recovered.

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

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

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

USE OF PROCEEDS

We expect to receive approximately $ million of net proceeds (assuming the midpoint of the price range set forth on the cover of this prospectus) from the sale of the common stock offered by us after deducting underwriting discounts and commissions and estimated offering expenses payable by us. If the underwriters exercise their option to purchase additional shares of common stock from the selling stockholder, we will not receive any proceeds from the sale of such shares.

We intend to use a portion of the net proceeds we receive from this offering to repay the $ million of outstanding indebtedness under our credit facility and the remaining net proceeds to fund a portion of our 2017 capital program. The following table illustrates our anticipated use of the net proceeds from this offering:


Sources of Funds (in millions)		Use of Funds (in millions)
Net proceeds from this offering	$	Repayment of our credit facility	$
		Funding a portion of our 2017 capital program

Total sources of funds	$	Total uses of funds	$

As of April 10, 2017, we had $380.0 million of outstanding borrowings under our credit facility and $5.0 million in outstanding letters of credit. Our credit facility matures on December 31, 2019, and bears interest at a variable rate. At December 31, 2016, the weighted average interest rate on borrowings under our credit facility was 3.10%. We also pay a commitment fee on unused amounts of our credit facility at an annual rate between 0.375% and 0.50%. The outstanding borrowings under our credit facility were incurred to partially fund previous acquisitions of oil and natural gas properties as well as to fund a portion of our 2015, 2016 and 2017 capital expenditures and general and administrative expenses. We may at any time reborrow amounts repaid under our credit facility, and we expect to do so from time to time following this offering to fund our 2017 capital program. We do not expect to draw down on our credit facility in connection with or shortly following this offering.

A $1.00 increase or decrease in the assumed initial public offering price of $ per share (the midpoint of the price range set forth on the cover page of this prospectus) would cause the net proceeds from this offering, after deducting the underwriting discounts and commissions and estimated offering expenses, received by us to increase or decrease, respectively, by approximately $ million, assuming the number of shares offered by us, as set forth on the cover page of this prospectus, remains the same. If the proceeds increase due to a higher initial public offering price, we would use the additional net proceeds to fund additional future capital expenditures. If the proceeds decrease due to a lower initial public offering price, then we would first reduce by a corresponding amount the net proceeds directed to funding a portion of our 2017 capital program and then, if necessary, the net proceeds directed to repay outstanding borrowings under our credit facility.

DIVIDEND POLICY

We do not anticipate declaring or paying any cash dividends to holders of our common stock in the foreseeable future. We currently intend to retain future earnings, if any, to finance our operations and the growth of our business. Our future dividend policy is within the discretion of our board of directors and will depend upon then-existing conditions, including our results of operations, financial condition, capital requirements, investment opportunities, statutory restrictions on our ability to pay dividends and other factors our board of directors may deem relevant. In addition, our credit agreement places certain restrictions on our ability to pay cash dividends.

CAPITALIZATION

The following table sets forth our cash and cash equivalents and capitalization as of December 31, 2016:

•

on an actual basis for our predecessor; and

•

on an as adjusted basis to give effect to our corporate reorganization as described under “Corporate Reorganization” and the sale of shares of our common stock in this offering at an assumed initial offering price of $ per share (which is the midpoint of the price range set forth on the cover page of this prospectus) and the application of the net proceeds we receive from this offering as set forth under “Use of Proceeds”.

The information set forth in the “As Adjusted” column of the table below is illustrative only and will be adjusted based on the actual initial public offering price and other final terms of this offering. This table should be read in conjunction with “Use of Proceeds” and the historical financial statements of our predecessor and accompanying notes included elsewhere in this prospectus.


	As of December 31, 2016
	Predecessor Actual		As Adjusted (1)
	(in thousands, except number of shares and par value)
Cash and cash equivalents	$	529	$

Long-term debt, including current maturities:
Credit Facility (2)	$	350,000	$

Total long-term debt	$	350,000	$

Equity:
Members’ equity	$	216,665
Preferred stock—$0.01 par value; no shares authorized, issued or outstanding, actual; shares authorized, no shares issued and as outstanding, as adjusted		—
Common stock—$0.01 par value; no shares authorized, issued, or outstanding, actual; shares authorized, shares issued and outstanding, as adjusted		—
Additional paid-in capital		—
Accumulated deficit		—

Total stockholders’ equity	$	216,665	$

Total capitalization	$	566,665	$

(1)

A $1.00 increase (decrease) in the assumed initial public offering price of $ per share, which is the midpoint of the price range set forth on the cover page of this prospectus, would increase (decrease) additional paid-in capital, total equity and total capitalization by approximately $ million, $ million and $ million, respectively, assuming that the number of shares offered by us, as set forth on the cover page of this prospectus, remains the same, after deducting the estimated underwriting discounts and commissions payable by us. We may also increase or decrease the number of shares we are offering. An increase (decrease) of one million shares offered by us at an assumed offering price of $ per share, which is the midpoint of the price range set forth on the cover page of this prospectus, would increase (decrease) additional paid-in capital, total equity and total capitalization by approximately $ million, $ million and $ million, respectively, after deducting the estimated underwriting discounts and commissions and estimated offering expenses payable by us.

(2)

As of April 10, 2017, our borrowing base under our credit facility was $385.0 million. As of April 10, 2017, we had $380.0 million of outstanding borrowings under our credit facility and $5.0 million in outstanding letters of credit (which reduce the availability under the credit facility on a dollar-for-dollar basis). After giving effect to the sale of shares of our common stock in this offering and the application of the anticipated net proceeds we receive from this offering, we expect to have $ million of available borrowing capacity under our credit facility.

DILUTION

Purchasers of our common stock in this offering will experience immediate and substantial dilution in the net tangible book value (tangible assets less total liabilities) per share of our common stock for accounting purposes. Our net tangible book value as of December 31, 2016, after giving pro forma effect to our corporate reorganization, was approximately $ million, or $ per share.

Pro forma net tangible book value per share is determined by dividing our net tangible book value, or total tangible assets less total liabilities, by our shares of common stock that will be outstanding immediately prior to the closing of this offering, including giving effect to our corporate reorganization. Assuming an initial public offering price of $ per share (which is the midpoint of the price range set forth on the cover page of this prospectus), after giving effect to the sale of the shares in this offering and further assuming the receipt of the estimated net proceeds (after deducting estimated underwriting discounts and commissions and estimated offering expenses payable by us), our adjusted pro forma net tangible book value as of December 31, 2016, would have been approximately $ million, or $ per share. This represents an immediate increase in the net tangible book value of $ per share to our existing stockholders and an immediate dilution to new investors purchasing shares in this offering of $ per share, resulting from the difference between the offering price and the pro forma as adjusted net tangible book value after this offering. The following table illustrates the per share dilution to new investors purchasing shares in this offering.


Assumed initial public offering price per share		$
Pro forma net tangible book value per share as of December 31, 2016 (after giving effect to our corporate reorganization)	$
Increase per share attributable to new investors in this offering

As adjusted pro forma net tangible book value per share (after giving effect to our corporate reorganization and this offering)

Dilution in pro forma net tangible book value per share to new investors in this offering		$

A $1.00 increase (decrease) in the assumed initial public offering price of $ per share, which is the midpoint of the price range set forth on the cover page of this prospectus, would increase (decrease) our as adjusted pro forma net tangible book value per share after the offering by $ and increase (decrease) the dilution to new investors in this offering by $ per share, assuming the number of shares offered by us, as set forth on the cover page of this prospectus, remains the same, after deducting the estimated underwriting discounts and commissions and estimated offering expenses payable by us.

The following table summarizes, on an adjusted pro forma basis as of December 31, 2016, the total number of shares of common stock owned by existing stockholders and to be owned by new investors at $ per share, which is the midpoint of the price range set forth on the cover page of this prospectus, and the total consideration paid and the average price per share paid by our existing stockholders and to be paid by new investors in this offering at $ , the midpoint of the price range set forth on the cover page of this prospectus, calculated before deduction of estimated underwriting discounts and commissions.


	Shares Acquired			Total Consideration			Average Price Per Share
	Number	Percent		Amount	Percent		Average Price Per Share
Existing stockholders			%	$		%	$
New investors in this offering

Total			100%	$		100%	$

The data in the table excludes shares of common stock reserved for issuance under our Long-Term Incentive Plan (which amount may be increased each year in accordance with the terms of our Long-Term Incentive Plan). If the underwriters’ option to purchase additional shares is exercised in full, the number of shares held by new investors will be increased to , or approximately % of the total number of shares of common stock, and the number of shares held by the existing stockholders will be correspondingly decreased.

SELECTED HISTORICAL CONSOLIDATED FINANCIAL DATA

The following table shows the summary historical consolidated financial data and selected unaudited pro forma financial data, for the periods and as of the dates indicated, of Tapstone Energy, LLC, our accounting predecessor. The historical consolidated financial data as of and for the years ended December 31, 2016 and 2015 were derived from the audited historical consolidated financial statements of our predecessor included elsewhere in this prospectus. The selected unaudited pro forma financial data is presented for informational purposes only.

You should read the following table in conjunction with “Use of Proceeds”, “Capitalization”, “Management’s Discussion and Analysis of Financial Condition and Results of Operations”, the historical consolidated financial statements of our predecessor and accompanying notes included elsewhere in this prospectus.


	Year Ended December 31,
	2016			2015
	(in thousands, except per share data)
Statement of Operations Data:
Revenues:
Oil sales	$	74,675		$	86,082
Natural gas sales		65,577			73,662
Natural gas sales, related parties		8,747			8,017
NGL sales		36,189			31,406
Transportation revenue		3,916			4,711

Total revenues		189,104			203,878

Expenses:
Production expense		72,687			64,771
Production taxes		4,329			8,274
Transportation cost of service		5,858			6,166
Depreciation and depletion – oil and natural gas		59,855			80,178
Depreciation and amortization – other		8,204			7,561
Accretion of asset retirement obligation		460			422
Impairment of oil and natural gas properties		237,378			282,469
General and administrative		9,749			11,688
General and administrative, related parties		5,060			4,549

Total expenses		403,580			466,078

Loss from operations		(214,476	)		(262,200	)

Other income (expense):
Interest expense		(12,643	)		(12,249	)
Gain/(Loss) on derivative contracts		(17,449	)		47,839
Other income, net		81			15

Total other income (expense)		(30,011	)		35,605

Net loss	$	(244,487	)	$	(226,595	)


	Year Ended December 31,
	2016			2015
	(in thousands, except per share data)
Pro Forma Information (1):
Net loss	$	(244,487	)
Pro forma benefit for income taxes		39,370

Pro forma net loss	$	(205,117	)

Pro forma loss per common share:
Basic and diluted	$
Weighted average pro forma shares outstanding:
Basic and diluted
Statements of Cash Flow Data:
Cash provided by (used in):
Operating activities	$	134,633		$	195,536
Investing activities		(190,646	)		(196,385	)
Financing activities		50,079			(2,500	)
Balance Sheet Data (at period end):
Cash and cash equivalents	$	529		$	6,463
Total assets		630,570			803,416
Long-term obligations		357,117			414,668
Total liabilities		413,905			457,017
Total members’ equity		216,665			346,399
Other Financial Data:
Adjusted EBITDA (2)	$	140,799		$	184,306

(1)

The net loss per common share and weighted average common shares outstanding reflect the estimated number of shares of common stock we expect to have outstanding upon the completion of our corporate reorganization described under “Corporate Reorganization”. The pro forma per-share data also reflects additional pro forma income tax benefit of $ million for the year ended December 31, 2016, associated with the income tax effects of the corporate reorganization described under “Corporate Reorganization” and this offering. Tapstone Energy Inc. is taxable as a corporation under the Internal Revenue Code of 1986, as amended (the “Code”), and as a result, will be subject to U.S. federal, state and local income taxes. Although our predecessor was subject to franchise tax in the State of Texas, it was treated as a partnership under the Code and generally passed through its taxable income to its owners for other income tax purposes and thus was not subject to U.S. federal income taxes or other state or local income taxes.

(2)	Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to net income, please read “Summary—Summary Historical Financial Data—Non-GAAP Financial Measure—Adjusted EBITDA”.

Non-GAAP Financial Measures

Adjusted EBITDA

We define Adjusted EBITDA as net income (loss) before interest expense, depreciation and depletion – oil and natural gas, depreciation and amortization – other, accretion of asset retirement obligation, impairment of oil and natural gas properties, income taxes, mark-to-market (“MTM”) gains or losses on derivative contracts, incentive unit compensation cost and acquisition and divestiture (“A&D”) costs. Adjusted EBITDA is not a measure of net income as determined by United States Generally Accepted Accounting Principles (“GAAP”).

The following table presents a reconciliation of Adjusted EBITDA to net income (loss), our most directly comparable financial measure calculated and presented in accordance with GAAP.


	Year Ended December 31,
	2016			2015
	(in thousands)
Net loss	$	(244,487	)	$	(226,595	)
Adjusted for
Interest expense		12,643			12,249
Depreciation and depletion – oil and natural gas		59,855			80,178
Depreciation and amortization – other		8,204			7,561
Accretion of asset retirement obligation		460			422
Impairment of oil and natural gas properties		237,378			282,469
Income taxes		—			—
Incentive unit compensation expense		4,757			4,705
MTM loss on derivative contracts (1)		61,356			21,093
A&D costs		633			2,224

Adjusted EBITDA	$	140,799		$	184,306

(1)	Includes the effect of adjusting net loss for changes in the fair value of derivative instruments, which are recognized at the end of each accounting period because we do not designate commodity derivative instruments as cash flow hedges.

PV-10

PV-10 is a non-GAAP financial measure 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 cash flows. 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.

The following table presents a reconciliation of PV-10 to the GAAP financial measure of standardized measure as of the date indicated.


	As of December 31,
	2016		2015
	(in thousands)
Standardized measure (1)	$	320,720	$	472,686
Present value of future income tax discounted at 10%		1,962		2,730

PV-10 of proved reserves	$	322,682	$	475,416

(1)

As of December 31, 2016 and 2015, we were a limited liability company and as a result, we were not subject to entity-level U.S. federal, state and local income taxes, other than the franchise tax in the State of Texas. Following our corporate reorganization, we will be subject to U.S. federal, state and local income taxes. Accordingly, estimates included herein of future net cash flows may be materially different from the future net cash flows that are ultimately received. Future calculations of standardized measure will include the effects of income taxes on future net cash flow. Please read “Risk Factors—The standardized measure of our estimated reserves is not an accurate estimate of the current fair value of our estimated reserves”.

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 Historical Consolidated Financial Data” and our consolidated financial statements and related notes appearing elsewhere in this prospectus. The following discussion 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, changes in oil, natural gas, and NGLs prices, production volumes, capital expenditures, uncertainties in estimating proved reserves, operational factors affecting the commencement or maintenance of producing wells, economic and competitive conditions, and uncertainties regarding environmental regulations or litigation and other legal or regulatory developments affecting our business, as well as those factors discussed below and elsewhere in this prospectus, particularly in “Risk Factors” and “Cautionary Statement Regarding Forward-Looking Statements”, all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. We do not undertake any obligation to update any forward-looking statements except as otherwise required by applicable law.

Overview

Tapstone Energy Inc. (“Tapstone”) was formed as a holding company in December 2016 and has not had any operations since its formation. Accordingly, Tapstone Energy Inc. does not have any historical financial operating results. Our accounting predecessor, Tapstone Energy, LLC, was formed as a Delaware limited liability company in September 2013. Pursuant to the terms of certain reorganization transactions that will be completed prior to the closing of this offering, we will acquire all of the membership interests in our predecessor in exchange for the issuance to our existing owners of all of our issued and outstanding shares of common stock (prior to the issuance of shares of common stock in this offering). As a result of these transactions, our predecessor will become our direct, wholly-owned subsidiary.

Market Conditions

The oil and natural gas industry is cyclical and commodity prices are highly volatile. In the second half of 2014, oil prices began a rapid and significant decline as the global oil supply began to outpace demand. During 2015 and 2016, the global oil supply continued to outpace demand, resulting in a sustained decline in realized prices for oil production. In general, the imbalance between supply and demand reflects the significant supply growth achieved in the United States as a result of shale drilling and oil production increases by certain other countries, including Russia and Saudi Arabia, as part of an effort to retain market share, combined with only modest demand growth in the United States and less-than-expected demand in other parts of the world. Although

there has been a dramatic decrease in drilling activity in the industry, oil storage levels in the United States remain at historically high levels. Until supply and demand balance and the overhang in storage levels begins to decline, prices will likely remain under pressure. The U.S. dollar has also strengthened relative to other leading currencies, which has caused oil prices to weaken, as they are U.S. dollar-denominated. In addition, the lifting of economic sanctions on Iran has resulted in increasing supplies of oil, adding further downward pressure to oil prices. Oil prices experienced considerable volatility during the third quarter 2016, with the WTI posted price falling to a low of $39.50 per barrel in early August before rebounding on the news that OPEC had agreed to the framework of an agreement that would limit production by its member countries. Oil prices have continued to rise in the fourth quarter 2016 and thus far in 2017 as OPEC formally announced its agreement to cut production by 1,200 MBbl/d on November 30, 2016, followed by the announcement in December that certain non-OPEC countries, including Russia, Mexico, Azerbaijan, Oman and Kazakhstan, had agreed to cut production by 558 MBbl/d. NGLs prices generally correlate to the price of oil. Also adversely affecting the price for NGLs is the supply of NGLs in the United States, which has continued to grow due to an increase in industry participants targeting the development of NGLs-prone acreage in recent years. Prices for domestic natural gas began to decline during the third quarter of 2014 and remained weak throughout 2015, 2016 and thus far in 2017, though natural gas prices have risen slightly during the fourth quarter of 2016. The declines in natural gas prices are primarily due to an imbalance between supply and demand across North America. Although the current downturn has begun to show signs of improvement, any long-term recovery continues to be uncertain and is dependent on a number of economic, geopolitical and monetary policy factors that are outside our control, and the market is likely to continue to be volatile in the future.

Our revenue, profitability and future growth are dependent on the prices we receive for our oil and natural gas production, as well as NGLs that are extracted from our natural gas during processing. Lower oil, natural gas and NGLs prices not only may decrease our revenues, but also may reduce the amount of oil, natural gas and NGLs that we can produce economically and therefore potentially decrease our oil, natural gas and NGLs reserves. Lower commodity prices in the future could also result in impairments of our properties and may also reduce the borrowing base of our credit facility, which is determined at the discretion of the lenders and is based on the collateral value of our proved reserves that have been mortgaged to the lenders. Please read “Risk Factors—Risks Related to Our Business—Any significant reduction in our borrowing base under our credit facility as a result of the periodic borrowing base redeterminations or otherwise may negatively impact our ability to fund our operations”. To manage risks related to fluctuations in prices attributable to our expected oil, natural gas, and NGLs production, we periodically enter into oil, natural gas and NGLs derivative contracts. While the use of these instruments limits the downside risk of adverse price changes, their use may also limit future revenues from favorable price changes.

Alternatively, higher oil and natural gas prices may result in significant non-cash fair value losses being incurred on our derivatives, which could cause us to experience net losses. Further, our capital and operating costs have historically risen during periods of increasing oil, natural gas and NGLs prices. These cost increases result from a variety of factors beyond our control, such as increases in the cost of electricity, steel and other raw materials that we and our vendors rely upon; increased demand for labor, services and materials as drilling activity increases; and increased taxes. Such costs may rise faster than increases in our revenue if commodity prices rise, thereby negatively impacting our profitability, cash flow and ability to complete development activities as scheduled and on budget. This impact may be magnified to the extent that our ability to participate in the commodity price increases is limited by our derivative activities. See “Risk Factors—Risks Related to Our Business—We could experience periods of higher costs if commodity prices rise. These increases could reduce our profitability, cash flow and ability to complete development activities as planned”.

How We Evaluate Our Operations

We use a variety of financial and operating metrics to assess the performance of our oil and gas operations, including:

•

the rate at which we replace our reserves;

•

production and revenue growth;

•

realized prices on the sale of oil, natural gas and NGLs (including the effect of our commodity derivative contracts);

•

production expense;

•

net income (loss); and

•

Adjusted EBITDA.

In addition to the operating metrics above, as we increase our reserve base, we will assess our capital spending by calculating our finding and development costs for our proved reserve additions. In evaluating our proved developed reserve additions, any reserve revisions for changes in commodity prices between years are excluded from the assessment, however, any performance related reserve revisions are included. We also evaluate our rates of return on invested capital in our wells. We review changes in drilling and completion costs, production expenses, oil, natural gas and NGLs prices, well production and other factors in order to focus our drilling on the highest rate of return areas within our acreage.

Sources of Our Revenues

Our revenues are derived from the sale of our oil and natural gas production, the sale of NGLs that are extracted from our natural gas during processing, and the transportation charges paid by certain third parties for their share of volumes that flow through our gathering and compression facilities. Revenues from product sales are a function of the volumes produced, product quality, market prices, and gas Btu content. We pay transportation costs either to a third party or as specified under our contract with the purchaser. We record transportation, gathering, and compression costs within production expense. Our revenues from oil, natural gas and NGLs sales do not include the effects of derivatives. For the year ended December 31, 2016, our revenues, excluding transportation revenue, were derived 40% from oil sales, 40% from natural gas sales and 20% from NGLs sales. For the year ended December 31, 2015, our revenues, excluding transportation revenue, were derived 43% from oil sales, 41% from natural gas sales and 16% from NGLs sales. Our revenues may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices.

Production Volumes

The following table presents historical production volumes for our properties for the years ended December 31, 2016 and 2015:


	Year Ended December 31,
	2016		2015
Oil (MBbls)		1,860		1,895
Natural Gas (MMcf)		32,484		31,024
NGLs (MBbls)		2,553		2,476

Total (MBoe)		9,827		9,542

Average MBoe/d		26.9		26.1

As reservoir pressures decline, production volumes from a given well or formation decreases and production expenses may increase. Growth in our future production and reserves will depend on our ability to continue to add proved reserves in excess of production. Our ability to increase reserves through development projects and acquisitions is dependent on many factors, including infrastructure capacity in our areas of

operation, our ability to raise capital, our ability to obtain regulatory approvals, and our ability to successfully identify and consummate acquisitions. Please read “—Critical Accounting Policies and Estimates—Oil and Gas Reserves” for further discussion.

Realized Prices on the Sales of Oil, Natural Gas and NGLs Volumes

Oil pricing is predominately determined by the physical market, supply and demand, financial markets and national and international politics. The NYMEX WTI futures price is a widely used benchmark in the pricing of domestic and imported oil in the United States. Our actual prices realized from the sale of oil can differ from the quoted NYMEX WTI price as a result of contract specific index pricing adjustment provisions with our purchaser. In our producing fields, oil is sold under two purchaser contracts tied to NYMEX pricing with monthly pricing provisions.

Natural gas prices vary by region, depending upon the distance to markets, availability of pipeline capacity and supply and demand relationships in that region. The NYMEX Henry Hub price of natural gas is a widely used benchmark for the pricing of natural gas in the United States. Our actual prices realized from the sale of natural gas can differ from the quoted NYMEX Henry Hub price as a result of quality and purchaser contract terms that are tied to a regional pricing index. Our natural gas is sold under multiple contracts tied to a regional pricing index and based on geographic location.

Similar to natural gas, NGLs are sold under multiple contracts and are tied to a regional pricing index based on geographic location. NGLs pricing is a function of the individual byproducts of gas and product quality can vary significantly by operational area.

The following table presents our realized commodity prices, as well as the effects of derivative settlements:


	Year Ended December 31,
	2016		2015
Crude Oil (per Bbl):
Unweighted average NYMEX price	$	43.40	$	48.79
Realized price, before the effects of derivative settlements	$	40.15	$	45.42
Effects of derivative settlements	$	8.25	$	18.42
Natural Gas:
Unweighted average NYMEX price (per MMBtu)	$	2.55	$	2.63
Realized price, before the effects of derivative settlements (per Mcf)	$	2.29	$	2.63
Effects of derivative settlements (per Mcf)	$	0.63	$	0.77
NGLs (per Bbl):
Realized price, before the effects of derivative settlements	$	14.17	$	12.68
Effects of derivative settlements	$	3.16	$	4.15

Derivative Contracts Activity

Our primary market risk exposure is in the price we receive for our oil, natural gas, and NGLs production. Pricing for oil, natural gas and NGLs production has been volatile and unpredictable for several years, and we expect this volatility to continue in the future. To achieve more predictable cash flow and to reduce our exposure to adverse fluctuations in commodity prices, from time to time we enter into derivative arrangements for our oil, natural gas and NGLs production. Our hedging instruments allow us to reduce, but not eliminate, the potential effects of the variability in cash flow from operations due to fluctuations in oil, natural gas and NGLs prices and provide increased certainty of cash flows. While the use of these instruments limits the downside risk of adverse price changes, their use may also limit future revenues from favorable price changes.

We will sustain losses to the extent our derivative contract prices are lower than market prices and, conversely, we will sustain gains to the extent our derivative contract prices are higher than market prices. These derivatives are not designated as a hedging instrument for hedge accounting under GAAP and as such, changes in fair value are recorded in income. Please read “—Quantitative and Qualitative Disclosure About Market Risk—Commodity Price Risk” for further discussion.

Our hedging strategy and future hedging transactions will be determined primarily at our discretion and may differ from historical hedging activity. Further, under our credit agreement, we were required to enter into swap contracts by December 31, 2016 which remain in effect for the calendar year 2017 covering at least 3,300 Bbls/d of oil and at least 5,100 Bbls/d of NGLs. We have satisfied the requirement under our credit agreement to enter into these swaps.

There are a variety of hedging strategies and instruments used to hedge future price risk. Our swap contracts establish that we will receive a fixed price for our production and pay a variable market price to the contract counterparty. When the settlement price is below the fixed price, the counterparty pays us an amount equal to the difference between the settlement price and the fixed price multiplied by the hedged contract volume. When the settlement price is above the fixed price, we pay our counterparty an amount equal to the difference between the settlement price and the fixed price multiplied by the hedged contract volume. We expect to use a variety of hedging strategies and instruments to hedge our price risk in the future.

Our open positions executed as of December 31, 2016 are reflected in the table below.


	Three Months Ended								Year Ended
	March 31, 2017		June 30, 2017		September 30, 2017		December 31, 2017		December 31, 2018		Total
Crude Oil Swaps
Notional Volumes (Bbl)		270,000		273,000		331,200		331,200		—		1,205,400
Notional Volumes (Bbl/d)		3,000		3,000		3,600		3,600		—		3,302
Weighted average fixed price ($/Bbl)	$	52.78	$	52.78	$	53.21	$	53.21	$	—	$	53.02
NGLs Swaps
Notional Volumes (Bbl)		450,000		455,000		469,200		487,600		—		1,861,800
Notional Volumes (Bbl/d)		5,000		5,000		5,100		5,300		—		5,101
Weighted average fixed price ($/Bbl)	$	23.42	$	23.42	$	23.45	$	23.50	$	—	$	23.45

Our open positions executed as of March 23, 2017 are reflected in the table below.


	Three Months Ending								Year Ending
	March 31, 2017		June 30, 2017		September 30, 2017		December 31, 2017		December 31, 2018		Total
Crude Oil Swaps
Notional Volumes (Bbl)		24,000		273,000		331,200		331,200		365,000		1,324,400
Notional Volumes (Bbl/d)		3,000		3,000		3,600		3,600		1,000		2,044
Weighted average fixed price ($/Bbl)	$	52.78	$	52.78	$	53.21	$	53.21	$	56.10	$	53.91
Natural Gas Swaps
Notional Volumes (MMbtu)		160,000		4,095,000		4,140,000		5,060,000		1,350,000		14,805,000
Notional Volumes (MMbtu/d)		20,000		45,000		45,000		55,000		15,000		39,629
Weighted average fixed price ($/MMbtu)	$	3.45	$	3.31	$	3.31	$	3.32	$	3.34	$	3.32
NGLs Swaps
Notional Volumes (Bbl)		40,000		455,000		469,200		487,600		—		1,451,800
Notional Volumes (Bbl/d)		5,000		5,000		5,100		5,300		—		5,130
Weighted average fixed price ($/Bbl)	$	23.42	$	23.42	$	23.45	$	23.50	$	—	$	23.46

Our historical derivative positions and the settlement amounts for each of the periods indicated are reflected in the table below.


	Year Ended December 31,
	2016		2015
Crude Oil Swaps
Notional Volumes (Bbl)		999,224		1,115,693
Weighted average fixed price ($/Bbl)	$	59.68	$	80.35
Natural Gas Swaps
Notional Volumes (MMBtu)		14,366,213		18,928,143
Weighted average fixed price ($/MMBtu)	$	3.87	$	3.95
NGLs Swaps
Notional Volumes (Bbl)		1,141,067		1,524,953
Weighted average fixed price ($/Bbl)	$	24.86	$	24.19

Primary Components of Our Cost Structure

Production expense. Our production expense, also commonly referred to as lease operating expense, is the day-to-day expense incurred to operate and maintain our oil and natural gas properties. The expenses in this category include all direct and allocated indirect costs including utilities, produced waste water disposal, field personnel, compression/dehydration, chemicals, equipment rental, supplies, routine repairs and maintenance and other expenses incurred in bringing hydrocarbons from a producing formation to the surface. Certain of our operating cost components are variable and increase or decrease as the level of produced hydrocarbons and water increases or decreases.

Production expense also includes commodity transportation and gathering fees, ad valorem taxes and insurance expense. Transportation, processing, gathering and other operating expenses principally consist of expenditures to prepare and transport production from the wellhead to a specified sales point and gas processing costs. These costs will fluctuate with increases or decreases in production volumes, contractual fees and changes in fuel and compression costs. We are also subject to ad valorem taxes in the counties where our production is

located. Ad valorem taxes vary by state and are generally based on either a valuation of our oil and natural gas reserves or a valuation of the surface equipment for our oil and natural gas properties.

Production taxes. Production taxes, also commonly referred to as severance taxes, are paid based on a percentage of revenues from production sold at fixed rates established by federal, state or local taxing authorities. In general, the production taxes we pay correlate to the changes in our oil, natural gas and NGLs revenues.

Transportation cost of service. Transportation cost of service expenses include maintenance, chemical, labor and insurance that are incurred in the operation of our gathering and compression facilities.

Depreciation and depletion – oil and natural gas. Depreciation and depletion – oil and natural gas is the systematic expensing of the capitalized costs incurred to acquire, explore and develop oil, natural gas and NGLs. As a “full cost” company, all costs incurred in the acquisition, exploration and development of properties (including costs of surrendered and abandoned leaseholds, delay lease rentals, dry holes and overhead related to exploration and development activities) are capitalized. Capitalized costs are depleted using the units of production method. Please read “—Critical Accounting Policies and Estimates—Full Cost Method of Accounting” for further discussion.

Depreciation and amortization – other. Depreciation and amortization – other is the systematic expensing of capitalized costs incurred primarily related to our Wheeler Midstream asset. Depreciation of such gathering and compression equipment is computed using the straight-line method over the estimated useful lives of the assets, which range from 20 to 25 years.

Accretion of asset retirement obligation. We record the fair value of the legal liability for an asset retirement obligation (“ARO”) in the period in which the liability is incurred (at the time the wells are drilled or acquired) at the asset’s inception, with the offsetting increase to property cost. The liability accretes each period until it is settled or the well is sold, at which time the liability is removed.

Impairment of oil and natural gas properties. Under the full cost method of accounting we are required to perform a ceiling test for each cost center. If the net book value of our oil and natural gas properties exceeds the ceiling, a non-cash impairment is required. Please read “—Critical Accounting Policies and Estimates—Full Cost Method of Accounting” for further discussion.

General and administrative. General and administrative (“G&A”) costs include corporate overhead such as payroll and benefits for our corporate staff, incentive unit compensation cost, office rent for our headquarters, audit and other fees for professional services and legal compliance. G&A expenses are reported net of recoveries from other owners in properties operated by us and amounts capitalized pursuant to the full cost method. Please read “—Critical Accounting Policies and Estimates—Full Cost Method of Accounting” for further discussion. We expect that we will incur additional general and administrative expenses as a result of being a publicly-traded company.

Interest expense. We have financed a portion of our working capital requirements and drilling activities with borrowings under our credit facility. As a result, we incur interest expense that is affected by the level of borrowings, as well as fluctuations in interest rates. Interest expense is reported net of amounts capitalized pursuant to the full cost method. Please read “—Critical Accounting Policies and Estimates—Full Cost Method of Accounting” for further discussion.

Adjusted EBITDA

incentive unit compensation and acquisition and divestiture (“A&D”) costs. Adjusted EBITDA is not a measure of net income as determined by GAAP. Adjusted EBITDA should not be considered as an alternative to, or more meaningful than, net income as determined in accordance with GAAP or as an indicator of our operating performance. Certain items excluded from Adjusted EBITDA are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as the historic costs of depreciable assets and exploration expenses, none of which are components of Adjusted EBITDA. Our computations of Adjusted EBITDA may not be comparable to other similarly titled measures of other companies. For further discussion, please read “Summary—Summary Historical Financial Data—Non-GAAP Financial Measure”.

Factors That Significantly Affect Comparability of Our Financial Condition and Results of Operations

Our historical financial condition and results of operations for the periods presented may not be comparable, either from period to period or going forward, primarily for the reasons described below.

Impairment Charges

Under the full cost method, the net book value of the oil and natural gas properties may not exceed the estimated after-tax future net cash flows from proved oil and natural gas properties, discounted at 10% (known as the ceiling test limitation). An amount of any future impairments from ceiling test limitations is difficult to reasonably predict and will depend upon not only commodity prices but also other factors that include, but are not limited to, incremental proved reserves that may be added each period, revisions to previous reserve estimates, capital expenditures, operating costs and all related tax effects. The ceiling limitation calculation is not intended to be indicative of the fair market value of our proved reserves or future results. Impairment charges do not affect cash flow from operating activities, but do adversely affect our net income (loss) and various components of our balance sheet. Any recorded impairment of oil and natural gas properties is not reversible at a later date. Please read “—Critical Accounting Policies and Estimates—Full Cost Method of Accounting” for further discussion.

Public Company Expenses

Upon completion of this offering, we expect to incur direct, incremental G&A expenses as a result of being a publicly traded company, including, but not limited to, costs associated with hiring new personnel, Sarbanes-Oxley compliance, implementation of compensation programs that are competitive with our public company peer group, costs associated with annual and quarterly reports and our other filings with the SEC, exchange listing fees, tax return preparation, independent auditor fees, investor relations activities, registrar and transfer agent fees, incremental director and officer liability insurance costs and independent director compensation. These direct, incremental G&A expenses are not included in our historical results of operations.

Incentive Unit Compensation

The governing documents of our predecessor provide for the issuance of incentive units, which are intended to constitute “profits interests” for federal income tax purposes, to certain employees and contractors. These equity-based awards are subject to time-based vesting requirements, as well as accelerated vesting upon the occurrence of a change of control. Payouts are triggered after the recovery of specified members’ capital contributions plus satisfaction of a certain internal rate of return. GAAP generally requires that all equity awards granted to employees be accounted for at fair value and recognized as compensation cost over the vesting period. In determining the appropriate accounting treatment of incentive units, we considered the characteristics of the incentive units in terms of treatment as stock-based compensation.

Due to vesting provisions within our incentive unit agreements, incentive units granted to employees are accounted for at grant date fair value and recognized as compensation cost ratably over the vesting period. Total

compensation cost related to the incentive units was $5.1 million and $5.0 million for the years ended December 31, 2016 and 2015, respectively. For the years ended December 31, 2016 and 2015, we capitalized incentive unit compensation of $0.4 million and $0.3 million, respectively, relating to exploration and development efforts. As of December 31, 2016, we had $2.6 million of total unrecognized compensation cost related to incentive units.

In connection with the completion of this offering, it is possible that the financial internal rate of return threshold associated with incentive unitholder participation in distributions will be satisfied. As part of the transactions described under “Corporate Reorganization,” our direct, wholly-owned subsidiary will merge with and into our predecessor, and our predecessor will be the surviving entity in such merger, with the equity holders in our predecessor, including the holders of incentive units, receiving an aggregate number of shares of our common stock. The actual allocation of shares between the equity holders of our predecessor will be determined after the closing of this offering based on the volume weighted average price of the publicly traded shares of our common stock during the initial 20 days during which our common stock is traded on the NYSE though the aggregate number of shares held by all of our Existing Owners will not be affected by such volume weighted average. All of the incentive units held by employees (and certain former employees and consultants) of Tapstone Energy, LLC will vest in full and convert into shares of our common stock in connection with the closing of this offering. As a result, unrecognized compensation costs associated with unvested incentive units would accelerate and become fully recognized.

Income Taxes

Tapstone is a corporation for federal income tax purposes, and as a result, will be subject to U.S. federal, state and local income taxes. Although our predecessor was subject to franchise tax in the state of Texas (at less than 1% of modified pre-tax earnings), it generally passed through its taxable income to its owners for other income tax purposes and thus was not subject to U.S. federal income taxes or other state or local income taxes. Accordingly, the financial data attributable to our predecessor contains no provision for U.S. federal income taxes or income taxes in any state or locality other than franchise tax in the State of Texas. We estimate that we will be subject to U.S. federal, state and local taxes at a blended statutory rate of approximately 38% of pre-tax earnings.

Historical Results of Operations and Operating Expenses

Year Ended December 31, 2016 Compared to the Year Ended December 31, 2015

Revenues. The following table provides the components of our revenues for the periods indicated, as well as each period’s respective average prices and production volumes:


	Year Ended December 31,
	2016		2015		Change			% Change
Revenues (in thousands):
Oil sales	$	74,675	$	86,082	$	(11,407	)		(13%)
Natural gas sales		74,324		81,679		(7,355	)		(9%)
NGL sales		36,189		31,406		4,783			15%
Transportation revenue		3,916		4,711		(795	)		(17%)

Total revenues	$	189,104	$	203,878	$	(14,774	)		(7%)

Average sales price:
Oil (per Bbl)	$	40.15	$	45.42	$	(5.27	)		(12%)
Natural gas (per Mcf)		2.29		2.63		(0.34	)		(13%)
NGL (per Bbl)		14.17		12.68		1.49			12%

Total (per Boe)	$	18.84	$	20.87	$	(2.03	)		(10%)
Production:
Oil (MBbls)		1,860		1,895		(35	)		(2%)
Natural gas (MMcf)		32,484		31,024		1,460			5%
NGL (MBbls)		2,553		2,476		77			3%

Total (MBoe)		9,827		9,542		285			3%

Average daily production volume:
Oil (Bbls/d)		5,082		5,192		(110	)		(2%)
Natural gas (Mcf/d)		88,753		84,997		3,756			4%
NGL (Bbls/d)		6,976		6,784		192			3%

Total (Boe/d)		26,850		26,142		708			3%

As reflected in the table above, our total revenues for the year ended December 31, 2016 were 7%, or $14.8 million, lower than total revenues for the year ended December 31, 2015. The decrease was primarily due to a decrease in commodity prices, resulting in a 10% decrease in average sales price per Boe, which was slightly offset by a 3% increase in production volumes sold in the year ended December 31, 2016 compared to the year ended December 31, 2015. The change in average sales price is primarily a result of both the fluctuation in the price of NYMEX WTI and the Panhandle Natural Gas Index (or similar regional index). Our volumes increased primarily as a result of the development of our NW Stack properties.

Oil sales decreased 13%, or $11.4 million, for the year ended December 31, 2016 compared to the prior year primarily due to a 12% decrease in the average sales price per Bbl. Natural gas sales decreased 9%, or $7.4 million, for the year ended December 31, 2016 compared to the prior year primarily due to a 13% decrease in the average sales price per Mcf, which was slightly offset by a 5% increase in natural gas volumes sold. NGLs sales increased 15%, or $4.8 million, for the year ended December 31, 2016 compared to the prior year due to a 12% increase in the average sales price per Bbl and a 3% increase in NGLs volumes sold.

Transportation revenue decreased 17%, or $0.8 million, for the year ended December 31, 2016 compared to the prior year primarily due to a decrease in oil and natural gas production volumes from our Stiles Ranch wells that are associated with our operated gathering and compression facilities. Transportation revenue is derived from charges paid by certain third parties for their share of volumes that flow through our gathering and compression facilities and represents approximately 21% of the gross fees charged to applicable revenue interest owners for each of the years ended December 31, 2016 and 2015.

The following table summarizes our expenses for the periods indicated and includes per Boe information we use to evaluate our performance relative to our peers and to identify and measure trends we believe may require additional analysis:


	Year Ended December 31,
	2016		2015		Change		% Change
Expenses (in thousands):
Production expense	$	72,687	$	64,771	$	7,916		12%
Production taxes		4,329		8,274		(3,945)		(48%)
Transportation cost of service		5,858		6,166		(308)		(5%)
Depreciation and depletion – oil and natural gas		59,855		80,178		(20,323)		(25%)
Depreciation and amortization – other		8,204		7,561		643		9%
Accretion of asset retirement obligation		460		422		38		9%
Impairment of oil and natural gas properties		237,378		282,469		(45,091)		(16%)
General and administrative		9,749		11,688		(1,939)		(17%)
General and administrative, related parties		5,060		4,549		511		11%

Total expenses	$	403,580	$	466,078	$	(62,498)		(13%)

Expenses (per Boe):
Production expense	$	7.40	$	6.79		0.61		9%
Production taxes		0.44		0.87		(0.43)		(49%)
Transportation cost of service		0.60		0.65		(0.05)		(8%)
Depreciation and depletion – oil and natural gas		6.09		8.40		(2.31)		(28%)
Depreciation and amortization – other		0.83		0.79		0.04		5%
Accretion of asset retirement obligation		0.05		0.04		0.01		5%
Impairment of oil and natural gas properties		24.16		29.60		(5.44)		(18%)
General and administrative		0.99		1.22		(0.23)		(19%)
General and administrative, related parties		0.51		0.48		0.03		6%

Total expenses	$	41.07	$	48.84	$	(7.77)		(16%)

Production expense. Production expenses increased 12%, or $7.9 million, for the year ended December 31, 2016 compared to the prior year. The increase is primarily related to a 3% increase in production sold for the year ended December 31, 2016 compared to the prior year. We experience increases in operating expenses as our well count increases. In addition, certain of our production expense components are variable and increase as production volumes increase. Production expense per Boe increased 9% for the year ended December 31, 2016 compared to the prior year. This increase is primarily related to an increase in production expense per Boe in the NW Stack compared to our legacy producing properties. Cost efficiencies associated with the production of our legacy producing properties are anticipated to be realized in the NW Stack as our operational expertise increases with continued development.

Production taxes. Production taxes decreased 48%, or $3.9 million, for the year ended December 31, 2016 compared to the prior year. The decrease is primarily related to lower sales revenues from lower realized

commodity prices in all areas and lower tax rates associated with Oklahoma and Texas exemptions on new horizontally-drilled wells. Production taxes as a percentage of our revenue was 2.3% for the year ended December 31, 2016 compared to 4.2% for the prior year.

Transportation cost of service. Transportation cost of service, which represents the cost incurred in the operation of our Wheeler Midstream gathering and compression facilities, was flat for the periods presented.

Depreciation and depletion – oil and natural gas. Depreciation and depletion – oil and natural gas expenses decreased 25% to $59.9 million for the year ended December 31, 2016 from $80.2 million for the year ended December 31, 2015. The decrease is primarily the result of $237.4 million and $282.5 million in impairment charges incurred for the years ended December 31, 2016 and 2015, respectively, which contributed to a decrease in the depletion rate to $6.09 per Boe for the year ended December 31, 2016 from $8.40 per Boe for the year ended December 31, 2015.

Depreciation and amortization – other. Depreciation and amortization – other expenses increased 9% to $8.2 million for the year ended December 31, 2016 from $7.6 million for the year ended December 31, 2015. The increase is primarily due to an increase in the related corporate overhead capital costs.

Accretion of asset retirement obligation. Accretion of asset retirement obligation expenses increased 9% to $0.46 million for the year ended December 31, 2016 from $0.42 million for the year ended December 31, 2015. The increase is primarily the result of the associated ARO liability increase from new wells being drilled in NW Stack.

Impairment of oil and natural gas properties. Impairment expenses for the year ended December 31, 2016 were $237.4 million, compared to $282.5 million for the year ended December 31, 2015. The impairment is primarily the result of decreases in the trailing twelve-month average prices for oil and natural gas. If pricing conditions decline further, we may incur full cost ceiling impairments in future quarters, the magnitude of which will be affected by one or more of the other components of the ceiling test calculations, until prices stabilize or improve over a twelve-month period.

General and administrative. G&A expenses decreased 17%, or $1.9 million, for the year ended December 31, 2016 compared to the prior year. The change is primarily related to a three-month service agreement that provided corporate overhead functions in connection with an acquisition during the first quarter 2015 totaling $1.5 million. G&A expenses are reported net of overhead recoveries from third parties and capitalized general and administrative expenses of $14.1 million and $13.3 million for the years ended December 31, 2016 and 2015, respectively.

General and administrative, related parties. General and administrative, related parties expenses increased 11%, or $0.5 million, for the year ended December 31, 2016 compared to the prior year. The increase is primarily related to an increase in rent expense attributable to the relocation of our corporate headquarters that occurred in the first half of 2015.

Other income and expenses. The following table provides the components of our other income and expenses for the periods indicated:


	Year Ended December 31,
	2016			2015			Change			% Change
Other income (expense) (in thousands):
Interest expense	$	(12,643	)	$	(12,249	)	$	(394	)		3%
Gain (loss) on derivative contracts, net		(17,449	)		47,839			(65,288	)		(136%)
Other income (expense), net		81			15			66			440%

Total other income (expense)		(30,011	)		35,605			(65,616	)		(184%)

Interest expense. Interest expense increased 3%, or $0.4 million, primarily due to a decrease in our borrowing base in April 2016 that placed us in a higher interest rate tier during the year ended December 31, 2016 compared to the prior year. Additionally, the LIBOR rate associated with our credit facility increased during the year ended December 31, 2016. These increases were offset by a decrease in the weighted average monthly outstanding borrowing balance during December 31, 2016 compared to the prior year. Our interest expense consists of interest expense on our long term debt, amortization of debt issuance costs, and is net of capitalized interest.

Gain (loss) on derivative contracts, net. For the year ended December 31, 2016, we recognized a $17.4 million derivative net loss, of which $43.9 million was cash settlements, offset by a $61.4 million MTM loss on derivatives. For the year ended December 31, 2015, we recognized a $47.8 million derivative net gain, of which $68.9 million was cash settlements, offset by a $21.1 million MTM loss on derivatives. Net losses and gains on our derivatives are a function of fluctuations in the underlying commodity prices and the monthly settlement of the instruments.

Liquidity and Capital Resources

We expect that our primary sources of liquidity and capital resources after the consummation of this offering will be internally generated cash flow from operations and borrowings under our credit facility. To the extent our capital requirements exceed our cash on hand, we may also issue debt or equity securities to fund these requirements. Long-term cash flows are subject to a number of variables including the level of production and prices we receive for our production as well as various economic conditions that have historically affected the oil and natural gas business. There can be no assurance that internal cash flows and other capital sources will provide sufficient funds to maintain capital expenditures that we believe are necessary to offset inherent declines in production and proven reserves.

Historically, our primary sources of liquidity have been capital contributions from our members, borrowings under our credit facility and cash flows from operations. To date, our primary use of capital has been for the acquisition, exploration and development of proved and unproved oil and natural gas properties. Our borrowings under our credit facility were $350.0 million and $408.0 million at December 31, 2016 and December 31, 2015, respectively. As of April 10, 2017, our borrowing base under our credit facility was $385.0 million. As of April 10, 2017, we had $380.0 million of outstanding borrowings under our credit facility and $5.0 million in outstanding letters of credit (which reduce the availability under the credit facility on a dollar-for-dollar basis). Subject to changes in commodity prices, we would expect the available borrowing capacity under our credit facility to increase as we convert proved undeveloped reserves to proved developed producing reserves, which may provide us additional flexibility in the future. Prior to this offering, we may seek to raise additional capital through equity financing or secured or unsecured debt financing.

We plan to continue our practice of entering into hedging arrangements to reduce the impact of commodity price volatility on our cash flow from operations. Under this strategy, we expect to maintain an active hedging program that seeks to reduce our exposure to commodity prices and protect our cash flow.

Because we are the operator of a high percentage of our acreage, the amount and timing of our capital expenditures is largely discretionary and within our control. We could choose to defer a portion of these planned capital expenditures depending on a variety of factors, including, but not limited to, the success of our drilling activities, and prevailing and anticipated prices for oil and natural gas. A deferral of planned capital expenditures, particularly with respect to drilling and completing new wells, could result in a reduction in anticipated production and cash flows and loss of acreage through lease expirations. 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.

For the years ended December 31, 2016 and 2015, our aggregate drilling, completion and leaseholds capital expenditures were approximately $185.1 million and $180.3 million, respectively, excluding acquisitions.

Our 2017 capital budget, which includes estimated expenditures for drilling, completions, leasing activity, the purchase of 3D seismic data, workover and other capitalized items is approximately $257 million. We intend to allocate $205 million, or 80%, of our 2017 capital budget to the development of our inventory of identified horizontal drilling locations in the NW Stack. We plan to drill 39 gross wells, 13 of which we anticipate to be two-mile laterals. Approximately 56% of our planned wells in 2017 will be targeting the oil window, with the remaining wells targeting the natural gas condensate window. Of the 39 gross wells we expect to drill, we expect to bring 29 wells to first sales during 2017. We intend to use the remaining $52 million of our capital budget for the purchase of 3D seismic data, leasing activities in the NW Stack and additional capitalized items. Our 2017 capital budget excludes any amounts that may be paid for acquisitions.

Cash Flows

Year Ended December 31, 2016 Compared to the Year Ended December 31, 2015

The following table provides the components of our cash flows for the periods indicated (in thousands).


	Year Ended December 31,
	2016			2015			Change			% Change
Net cash provided by operating activities		134,633			195,536			(60,903	)		(31	%)
Net cash used in investing activities		(190,646	)		(196,385	)		5,739			(3	%)
Net cash provided by (used in) financing activities		50,079			(2,500	)		52,579			2,103	%

Net cash provided by operating activities. Net cash provided by operating activities is primarily affected by the price of oil, natural gas and NGLs production volumes and changes in working capital. The decrease of 31%, or $60.9 million, in net cash provided by operating activities for the year ended December 31, 2016 compared to the year ended December 31, 2015 was primarily due to a $25.0 million decrease in derivatives settlements, a $18.7 million decrease in cash flow from working capital and a $14.8 million decrease in revenue attributable to a decline in commodity prices.

Net cash used in investing activities. Net cash used in investing activities is primarily affected by our capital budget for oil and natural gas properties. The decrease of 3%, or $5.7 million, in net cash used in investing activities for the year ended December 31, 2016, compared to the year ended December 31, 2015, is primarily related to a $11.8 million decrease in oil and natural gas property acquisition costs and a $5.5 million decrease in corporate overhead capitalized costs. The decrease in net cash used in investing activities was offset by an increase of $9.4 million in drilling and leasehold acquisition activity in the NW Stack area.

Net cash provided by (used in) financing activities. Net cash provided by or used in financing activities is primarily affected by activity with our credit facility and contributions from members. The increase of 2,103%, or $52.6 million, in net cash provided by financing for the year ended December 31, 2016, compared to the year ended December 31, 2015, is primarily the result of an increase of $109.6 million in capital contributions and an increase of $21.0 million in borrowings under our credit facility, offset by a $76.5 million increase in credit facility repayments.

Segment Reporting

Operating segments are defined as components of an enterprise that engage in activities from which it may earn revenues and incur expenses for which separate operational financial information is available, and this information is regularly evaluated by the chief operating decision maker for the purpose of allocating resources and assessing performance.

We operate in only one operating segment, which is the exploration and production of oil, natural gas and NGLs and related midstream activities. All revenues are derived from customers located in the United States. In addition, we have a single, company-wide management team that allocates capital resources to maximize profitability and measures financial performance as a single enterprise.

Our Credit Facility

On December 31, 2014, we entered into an amended and restated credit agreement (as amended, our “credit agreement”) with Bank of America, N.A., as administrative agent and issuing lender, and the lenders named therein, that provides for a revolving credit facility (our “credit facility”) with commitments of $1.0 billion (subject to the borrowing base). The credit agreement was amended on (a) November 17, 2016 pursuant to the First Amendment to Amended and Restated Credit Agreement and (b) March 31, 2017 pursuant to the Second Amendment to Amended and Restated Credit Agreement. This credit facility provides for borrowings to be used for the purpose of funding working capital, acquisitions, exploration and production operations, development (including the drilling and completion of producing wells), and for general business purposes and has a letter of credit sublimit of $50.0 million. As of April 10, 2017, the borrowing base under our credit facility was $385.0 million. On December 31, 2016, we had $350.0 million of outstanding borrowings under our credit facility and $5.0 million in outstanding letters of credit (which reduce the availability under the credit facility on a dollar-for-dollar basis). On April 10, 2017, we had $380.0 million of outstanding borrowings under our credit facility and $5.0 million in outstanding letters of credit. We intend to use a portion of the net proceeds from this offering to reduce amounts borrowed under our credit facility. Our credit facility matures on December 31, 2019 or, if December 31, 2019 is not a business day, on the next business day.

The amount available to be borrowed under our credit facility is subject to a borrowing base that is redetermined semiannually each April 1 and October 1 in an amount by the lenders at their sole discretion. Our next scheduled borrowing base redetermination is expected on or about October 1, 2017. However, the lenders will redetermine the borrowing base under our credit facility if we have not applied at least $250 million in net proceeds from this offering to prepay loans outstanding under the credit facility on or prior to May 15, 2017. If such a redetermination of the borrowing base occurs, we would not expect such redetermination to be effective sooner than July 2017. Additionally, at our option, we may request up to two additional redeterminations per year. The borrowing base depends on, among other things, the volumes of our proved reserves and estimated cash flows from these reserves and our commodity hedge positions as well as any other outstanding debt. Upon a redetermination of the borrowing base, if borrowings in excess of the revised borrowing capacity are outstanding, we could be required to immediately repay a portion of the debt outstanding under our credit agreement.

At our election, interest under the credit facility is determined by reference to (a) the London Interbank Offered Rate (“LIBOR”) plus an applicable margin between 1.50% and 2.50% per annum or (b) the “base rate,” which is the highest of (i) the federal funds rate plus 0.50%, (ii) the prime rate published by Bank of America or (iii) the Eurodollar rate (as defined in the credit facility) plus 1.00% per annum, plus, in each case under scenario (b), an applicable margin between 0.50% and 1.50% per annum. Interest is payable quarterly for base rate loans and at the applicable maturity date for LIBOR loans, except that if the interest period for a LIBOR loan is greater than three months, interest is paid at the end of each three-month period. Quarterly, we pay a commitment fee assessed at an annual rate between 0.375% and 0.50% on any available portion of the credit facility. We may repay any amounts borrowed prior to the maturity date without any premium or penalty other than customary LIBOR breakage costs.

The obligations under the credit facility are secured by substantially all our assets, including (i) proved oil, natural gas and NGLs reserves representing at least 80.0% of the discounted present value (as defined in the credit facility) of proved oil, natural gas and NGLs reserves considered by the lenders in determining the borrowing base for the credit facility, (ii) our gathering and compression facilities and (iii) the issued and outstanding equity interests directly owned by the borrower.

Our credit agreement contains restrictive covenants that limit our ability to, among other things:

•

incur certain additional indebtedness;

•

incur certain liens;

•

make certain investments;

•

make loans to others;

•

merge or consolidate with another entity;

•

sell assets;

•

make certain payments;

•

enter into transactions with affiliates;

•

enter into swap contracts; and

•

engage in certain other transactions without the prior consent of the lenders.

Each of the foregoing restrictions is subject to certain exceptions.

Our credit agreement also requires us to maintain compliance with a consolidated leverage ratio, which is the ratio of our Consolidated Funded Debt (as defined in our credit agreement) as of the last day of each fiscal quarter, subject to certain exclusions (as described in our credit agreement) to Consolidated EBITDAX (as defined in our credit agreement) for the period of four consecutive fiscal quarters ending on the last day of that fiscal quarter, of not greater than 4.0 to 1.0. As of December 31, 2016, we were in compliance with all financial covenants contained in our credit agreement.

Further, under our credit agreement, we were required to enter into swap contracts by December 31, 2016, which remain in effect for the calendar year 2017 covering at least 3,300 Bbls/d of oil and at least 5,100 Bbls/d of NGLs. We have satisfied the requirement under our credit agreement to enter into these swap contracts.

Contractual Obligations

A summary of our contractual obligations as of December 31, 2016, is provided in the following table (in thousands).


	Payments due by Period for the Year Ending December 31,
	2017		2018		2019		2020		2021		Thereafter		Total
Contractual Obligations:
Office lease – headquarters (1)	$	1,103	$	1,103	$	1,103	$	276		—		—	$	3,585
Volume commitment – crude oil (2)		2,300		2,300		2,300		575		—		—		7,475
Volume commitment – natural gas (3)		4,739		—		—		—		—		—		4,739
Credit facility and interest payable (4)		11,550		11,550		361,550		—		—		—		384,650

Total	$	19,692	$	14,953	$	364,953	$	851		—	$	—	$	400,449

(1)	We lease our headquarters office under an operating lease agreement terminating in March 2020. Base rent through the term of the lease is $1.1 million annually. Additionally, we lease our field offices for minimal amounts under agreements terminating in 2020.

(2)

Our crude oil sales agreement with Plains Marketing contains a minimum volume commitment requiring us to deliver 4,000 Bbl/d. The commitment, which has a five-year term ending March 2020, requires us to pay a per-barrel deficiency rate when delivery falls below 4,000 Bbl/d on a gross annual basis from April 1st through March 31st. The amounts represented above reflect the maximum liability under the commitment as if we produced zero volumes under the periods listed. Please read “Business—Operations—Transportation and Marketing.”

(3)

We are subject to a commitment requiring delivery of certain natural gas volumes to Enable under a 15-year agreement that terminates in December 2027. Such agreement requires us to pay per-MMBtu deficiency fees if the volume of natural gas we deliver from the applicable dedicated area during any six-month period beginning on either January 1 or July 1 of each year is less than 95% of the volume of natural gas we delivered from the dedicated area during the immediately preceding six-month period (subject to certain exceptions). The amount represented above reflects the maximum liability under the commitment as if we delivered no natural gas during the six-month period beginning January 1, 2017. Additionally, we incur minimal amounts related to a firm transportation agreement terminating in June 2018. Please read “Business—Operations—Transportation and Marketing.”

(4)

Calculated based on December 31, 2016 outstanding borrowings under our credit facility of $350.0 million and assumes no principal repayment until the maturity date December 2019. On a quarterly basis, interest is payable for base rate loans as well as commitment fees on the available portion of the credit facility. As of December 31, 2016, the borrowing base was $385.0 million and the interest rate under the credit facility was 3.25%. Please read “—Liquidity and Capital Resources—Our Credit Facility” for further discussion.

Quantitative and Qualitative Disclosure About Market Risk

We are exposed to market risk, including the effects of adverse changes in commodity prices and interest rates as described below. The primary objective of the following information is to provide quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in oil, natural gas and NGLs prices and interest rates. This forward-looking information provides indicators of how we view and manage our ongoing market-risk exposure. All of our market-risk sensitive instruments were entered into for purposes other than trading.

Commodity Price Risk

We are exposed to market risks related to the volatility of oil, natural gas and NGLs prices. Realized prices are primarily driven by worldwide prices for oil and spot market prices for North American gas production. The prices we receive for our oil, natural gas and NGLs production depend on many factors outside of our control, such as the strength of the global economy and global supply and demand for the commodities we produce.

To reduce the impact of fluctuations in oil prices on our revenues, we have periodically entered into commodity derivative contracts with respect to certain of our oil and natural gas production through various transactions that limit the downside of future prices received. We plan to continue our practice of entering into such transactions to reduce the impact of commodity price volatility on our cash flow from operations. For a discussion of how we use financial commodity derivative contracts to mitigate some of the potential negative impact on our cash flow caused by changes in natural gas prices, please read “—Critical Accounting Policies and Estimates—Commodity Derivative Instruments”.

Counterparty and Customer Credit Risk

Our cash and cash equivalents are exposed to concentrations of credit risk. We manage and control this risk by investing these funds with major financial institutions. We often have balances in excess of the federally insured limits.

The area within the Anadarko Basin in which we operate is served by multiple oil and natural gas customers, also called purchasers. Credit is extended based on an evaluation of the purchaser’s financial conditions and historical payment record. The future availability of a ready market for oil, natural gas and NGLs depends on numerous factors outside of our control, none of which can be predicted with certainty. Please read “Risk Factors—Risks Related to Our Business—We depend upon several significant customers for the sale of most of our oil, natural gas and NGLs production”. We do not believe the loss of any single purchaser would have a materially adverse effect on our ability to sell oil and natural gas production.

At December 31, 2016, we had commodity derivative contracts with two counterparties. We do not require collateral or other security from counterparties to support derivative instruments; however, to minimize the credit risk in derivative instruments, it is our policy to enter into derivative contracts only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market-makers. The creditworthiness of our counterparties is subject to periodic review. For the year ended December 31, 2016, we did not incur any losses with respect to counterparties failing to fulfill their payment obligations with our contracts.

Interest Rate Risk

We will be exposed to interest rate risk in the future if we draw on our credit facility. Interest on outstanding borrowings under our credit facility will accrue based on, at our option, LIBOR or the alternate base rate, in each case, plus an applicable margin that is determined based on our utilization of commitments under our credit facility. Please read “—Liquidity and Capital Resources—Our Credit Facility” for further discussion.

Critical Accounting Policies and Estimates

Use of Estimates in the Preparation of Financial Statements

The preparation of the 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 financial statements and the reported amounts of revenues and expenses during the reporting period. Significant items subject to such estimates and assumptions include proved oil and natural gas reserves, the use of these oil and natural gas reserves in calculating depletion, the use of the estimates of future net cash flows in computing ceiling test limitations, incentive unit compensation cost, fair value of assets and liabilities acquired in business combinations, and estimates of future abandonment obligations used in recording asset retirement obligations. Estimates and judgments are also required in determining allowance for doubtful accounts, impairments of undeveloped properties and other assets, fair value of derivative financial instruments, and amounts of commitments and contingencies, if any. Although management believes these estimates are reasonable, actual results could differ from these estimates.

Full Cost Method of Accounting

We use the full cost method of accounting for oil and natural gas properties whereby productive and nonproductive costs incurred in connection with the acquisition, exploration, and development of oil and natural gas reserves are capitalized. Salaries and benefits paid to employees and a portion of interest expense incurred from our credit facility that can be directly identified with acquisition, exploration, and development activities are also capitalized. Capitalized costs are depreciated using the unit-of-production method. Under this method,

depletion is computed at the end of each period by multiplying total production for the period by a depletion rate. The depletion rate is determined by dividing the total unamortized cost base plus future development costs by net equivalent proved reserves at the beginning of the period.

Capitalized costs associated with unproved properties are initially excluded from the amortizable cost base until a determination has been made as to the existence of proved reserves. The excluded costs are reviewed at the end of each period to determine whether the costs incurred should be reclassified to the full cost pool and, thereby, subjected to amortization. The costs associated with unproved activity relate primarily to costs to acquire unproved acreage. Unproved leasehold costs are transferred to the amortization base upon determination of the existence of proved reserves or upon impairment of a lease.

Under the full cost method, the net book value of the oil and natural gas properties may not exceed the estimated after-tax future net cash flows from proved oil and natural gas properties, using the preceding twelve-months’ average price based on closing prices on the first day of each month, discounted at 10%, plus the lower of cost or fair value of unproved properties, plus estimated salvage value (the ceiling limitation). The net book value is compared to the ceiling limitation on a quarterly and yearly basis. The excess, if any, of the net book value above the ceiling limitation is charged to expense in the period in which it occurs and is not subsequently reinstated. The ceiling limitation calculation is not intended to be indicative of the fair market value of our proved reserves or future results. Impairment charges do not affect cash flow from operating activities, but do adversely affect net income. For the years ended December 31, 2016 and 2015, we incurred a non-cash ceiling limitation write-down of our oil and natural gas properties of $237.4 million and $282.5 million, respectively.

Proceeds from the disposal of properties are normally deducted from the full-cost pool without recognition of gains or losses, except under circumstances where the deduction would significantly alter the relationship between capitalized costs and proved reserves of the cost center, in which case a gain or loss is recorded.

Oil and Gas Reserves

Our independent petroleum engineers and internal technical staff prepare the estimates of oil, natural gas and NGLs reserves and associated future net cash flows. Current accounting guidance allows only proved oil, natural gas and NGLs reserves to be included in our financial statement disclosures. Proved reserves are defined as the estimated quantities of oil, natural gas, and NGLs which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.

One of the most significant estimates we make is the estimate of oil, natural gas and NGLs reserves. Oil, natural gas and NGLs reserve estimates require significant judgments in the evaluation of all available geological, geophysical, engineering and economic data. The data for a given field may change substantially over time as a result of numerous factors including, but not limited to, additional development activity, production history, projected future production and economic assumptions relating to commodity prices, operating expenses, severance and other taxes, and capital expenditures, which assumptions are inherently uncertain. Accordingly, reserve estimates are generally different from the quantities of oil, natural gas and NGLs that are ultimately recovered. We cannot predict the amounts or timing of future reserve revisions.

Depreciation, Depletion, Amortization and Accretion

Our depletion rate, described above, is dependent upon our estimates of total proved reserves, which incorporate various assumptions and future projections. If our estimates of total proved reserves decline, the rate at which we record depletion expense increases, which in turn reduces our net income. Such a decline in reserves may result from lower commodity prices or other changes to reserve estimates, as discussed above, and we are unable to predict changes in reserve quantity estimates as such quantities are dependent on the success of our exploration and development program, as well as future economic conditions.

Commodity Derivative Instruments

To manage risks related to fluctuations in prices attributable to our expected oil, natural gas and NGLs production, we enter into oil, natural gas and NGLs derivative contracts. The objective of our use of commodity derivative instruments is to achieve more predictable cash flows in an environment of volatile oil and natural gas prices and to manage our exposure to commodity price risk. While the use of these commodity derivative instruments limits the downside risk of adverse price movements, such use may also limit our ability to benefit from favorable price movements.

Our derivatives are not designated as a hedging instrument for hedge accounting under GAAP and as such, changes in fair value are recorded in income. Net gains and losses on commodity derivative instruments are recorded based on the changes in the fair values of the derivative instruments. Our cash flow is only impacted when the actual settlements under the commodity derivative contracts result in making or receiving a payment to or from the counterparty.

Asset Retirement Obligations

Our AROs consist of estimated future costs associated with the plugging and abandonment of oil, natural gas and NGLs wells, removal of pipelines, equipment and facilities and land restoration in accordance with applicable local, state and federal laws. The fair value of an ARO liability is required to be recognized in the period in which it is incurred, with the associated asset retirement cost capitalized as part of the carrying cost of the oil and gas asset. The recognition of an ARO requires that management make numerous assumptions regarding such factors as the estimated probabilities, amounts and timing of settlements; the credit-adjusted risk-free discount rate to be used; and inflation rates. The liability is accreted each period and the capitalized cost is depleted as part of the full cost pool.

Revenue Recognition

Revenues from the sale of oil, natural gas and NGLs are recognized when the product is delivered at a fixed or determinable price, title has transferred, and collectability is reasonably assured and evidenced by a contract. We recognize revenues from the sale of oil, natural gas and NGLs using the sales method of accounting, whereby revenue is recorded based on our share of volume sold, regardless of whether we have taken our proportional share of volume produced. These differences result in gas imbalances. Liabilities are recorded for the imbalances greater than our proportionate share of remaining estimated natural gas reserves. At the end of the month, we estimate the amount of production delivered to purchasers and the price we will receive. We use our knowledge of our properties, contractual arrangements, NYMEX and regional spot market prices and other factors as the basis for these estimates. Variances between our estimates and the actual amounts received are recorded in the month payment is received.

Income Taxes

Prior to our conversion into a corporation in connection with this offering, we were organized as a Delaware limited liability company and were treated as a flow-through entity for U.S. federal and state income tax purposes. As a result, our net taxable income and any related tax credits were passed through to the members and were included in their tax returns even though such net taxable income or tax credits may not have actually been distributed.

Recently Issued Accounting Pronouncements

In August 2016, the FASB issued ASU 2016-15, “Classification of Certain Cash Receipts and Cash Payments”, which amends ASC Topic No. 230 “Statement of Cash Flows” and provides guidance and clarification on presentation of certain cash flow items. ASU 2016-15 is effective for fiscal years beginning after

December 15, 2017, and for interim periods within those fiscal years. We are currently assessing the impact of the adoption of ASU 2016-15. However, we do not expect adoption to have a material impact on our consolidated financial statements.

In June 2016, the FASB issued ASU 2016-13, “Measurement of Credit Losses on Financial Instruments”, which changes the impairment model for most financial assets and certain other instruments, including trade and other receivables, held-to-maturity debt securities and loans, and requires entities to use a new forward-looking expected loss model that will result in the earlier recognition of allowances for losses. ASU 2016-13 is effective for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. Early adoption is permitted for a fiscal year beginning after December 15, 2018, including interim periods within that fiscal year. Entities will apply the standard’s provisions as a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is adopted. We do not believe this standard will have a material impact on our consolidated financial statements.

In February 2016, the FASB issued ASU 2016-02, “Leases (Topic 842)”. ASU 2016-02 establishes a right-of-use (“ROU”) model that requires a lessee to record a ROU asset and a lease liability on the balance sheet for all leases with terms longer than 12 months. Leases will be classified as either finance or operating, with classification affecting the pattern of expense recognition in the income statement. The new standard is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. A modified retrospective transition approach is required for lessees for capital and operating leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements, with certain practical expedients available. We are currently evaluating the impact of this new standard on our consolidated financial statements.

In May 2014, the FASB issued ASU 2014-09, “Revenue from Contracts with Customers (Topic 606),” which outlines a new, single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance. This new revenue recognition model provides a five-step analysis in determining when and how revenue is recognized. The new model will require revenue recognition to depict the transfer of promised goods or services to customers in an amount that reflects the consideration a company expects to receive in exchange for those goods or services.

In August 2015, the FASB issued ASU 2015-14, “Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date,” which deferred the effective date of ASU 2014-09 by one year. That new standard is now effective for annual reporting periods beginning after December 15, 2017. We are currently evaluating the impact of this new standard. We do not expect adoption of the new standard to have a material impact on our consolidated financial statements, but additional financial statement disclosure is expected.

Inflation

Inflation in the United States has been relatively low in recent years and did not have a material impact on our results of operations for the years ended December 31, 2016 and 2015. Although the impact of inflation has been insignificant in recent years, it is still a factor in the United States economy, and we tend to experience inflationary pressure on the cost of oilfield services and equipment as increasing oil and natural gas prices increase drilling activity in our areas of operations.

Off-Balance Sheet Arrangements

Currently, we do not have any off-balance sheet arrangements.

BUSINESS

The following discussion should be read in conjunction with the “Selected Historical Consolidated Financial Data” and the accompanying financial statements and related notes included elsewhere in this prospectus.

The estimated proved reserve information for our properties as of December 31, 2016 contained in this prospectus are based on reserve reports relating to our properties prepared by Ryder Scott Company, L.P., independent petroleum engineers. The estimated proved reserve information for our properties as of December 31, 2015, contained in this prospectus is based on a reserve report relating to our properties prepared by Lee Keeling and Associates, Inc., independent petroleum engineers.

Our Company

Business Overview

Tapstone was formed in December 2013 with funding by GSO, a subsidiary of The Blackstone Group L.P. (“Blackstone”), with the goal of building a premier oil and natural gas company focused on acquiring and developing producing oil and natural gas properties in the Anadarko Basin. Our management and technical teams have extensive engineering, geoscience, land, marketing and finance capabilities and have collectively participated in the drilling of over 10,000 horizontal wells across multiple unconventional plays in the lower 48 states. Our management team is led by Steven C. Dixon, our Chairman, President and Chief Executive Officer and an industry veteran with over 36 years of experience in managing, developing and growing oil and natural gas business in some of the most prolific oil and natural gas plays in the United States.

The NW Stack

At our inception, we targeted the Anadarko Basin due to its established production history, multiple stacked benches, the extensive amount of technical information available and our management team’s substantial experience operating in the area. In 2014 we began focusing specifically on the NW Stack after results in the SCOOP and STACK plays definitively showed a productive trend towards our current position in the NW Stack. We began assembling our acreage position through a grassroots leasing program that we commenced in September 2014. As a result of our early identification of the resource potential of the NW Stack, as well as the general weakness in the oil and gas industry at the time, we were able to assemble a large, contiguous block of acreage in the NW Stack, which we do not believe would be possible to replicate in today’s market. Our acreage position in the NW Stack consists of approximately 200,000 net acres in the adjacent Oklahoma counties of Dewey, Woodward, Ellis and Major.

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data from over 900 existing vertical wells with Meramec and Osage penetrations previously drilled on or around our acreage;

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core samples and cuttings across each of the five identified benches;

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approximately 900 miles of 2D seismic data and over 300 square miles of 3D seismic data covering a portion of our acreage; and

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borehole imaging, density, porosity, resistivity and mud logs across our acreage.

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drilling and completing 33 Tapstone-operated horizontal wells across our position in each of the five identified benches; and

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analyzing over 50 horizontal wells drilled by offset operators on or around our acreage.

We refer to gross and net acreage where we are designated as operator or expect to be designated as operator based on the size of our working interest relative to other working interest owners as “our operated acreage” or acreage that we “operate” in this prospectus. As of December 31, 2016 we operated 78% of our net acreage in the NW Stack and had an average working interest of 72% in the 336 sections that we operated. For the three months ended December 31, 2016, our net production in the NW Stack was 5.1 MBoe/d, of which 14% was oil, 18% was NGLs and 68% was natural gas. For the year ended December 31, 2016, our net production in the NW Stack was 5.6 MBoe/d, of which 20% was oil, 18% was NGLs and 62% was natural gas. Of the 33 Tapstone-operated horizontal wells we have drilled and completed in the NW Stack as of March 23, 2017, three wells were in the Upper Meramec, four wells were in the Middle Meramec, seven wells were in the Lower Meramec, twelve wells were in the Upper Osage and seven wells were in the Lower Osage. Additionally, as of March 23, 2017, two Tapstone-operated horizontal wells were waiting on completion (one in the Lower Meramec and one in the Upper Osage) and four Tapstone-operated horizontal wells were in the process of being drilled (two in the Upper Meramec and two in the Lower Meramec).

The following map indicates the location of our operated horizontal wells that we have drilled and completed or are currently drilling in the NW Stack as of March 23, 2017.

LOGO

The following table presents data on the operated horizontal wells that we have drilled or are in the process of drilling in the NW Stack as of March 23, 2017. See “—Oil and Natural Gas Production Prices and Costs—Drilling Results”.


Well Name	Target Bench	First Production	Peak 30 IP (Boe/d) (1)(2)		Peak 30 IP (% Liquids) (1)(2)			Days to Drill		Total D&C ($MM) (3)
1. DENNIS 28-19-16 1H	Lower Osage	6/9/2015		1,911		35	%		71	$	7.0
2. BOZARTH 33-19-16 1H	Middle Meramec	8/25/2015		1,050		45	%		69	$	7.6
3. SHAW TRUST 30-22-19 1H	Middle Meramec	9/15/2015		631		67	%		38	$	5.8
4. WILSON 35-19-16 1H	Lower Osage	10/6/2015		1,328		44	%		46	$	5.3
5. BRANSTETTER 2-19-18 1H	Lower Meramec	11/26/2015		1,387		60	%		61	$	6.9
6. SEIFRIED TRUST 4-18-16 1H	Lower Osage	12/14/2015		1,473		30	%		69	$	6.8
7. HOWARD 5-19-17 1H	Upper Osage	1/9/2016		3,248		70	%		51	$	6.6
8. CARTER 29-19-17 1H	Lower Meramec	2/4/2016		1,790		43	%		44	$	5.0
9. IRVING 19-19-16 1H	Lower Osage	2/16/2016		971		45	%		50	$	5.4
10. WHITE 8-20-19 1H	Upper Osage	3/31/2016		1,359		39	%		51	$	5.0
11. YOUNG 6-20-18 1H	Middle Meramec	4/6/2016		475		15	%		45	$	5.4
12. RANDY 9-18-16 1H	Lower Osage	4/13/2016		1,381		33	%		59	$	5.6
13. CARA 28-20-18 1H	Lower Meramec	5/27/2016		584		48	%		52	$	5.4
14. RANDALL 15-20-20 1H	Upper Osage	6/3/2016		1,851		52	%		49	$	5.1
15. SEIDEL 5-19-18 1H	Lower Meramec	6/27/2016		675		36	%		48	$	5.0
16. SALISBURY 27-19-20 1H	Lower Osage	7/12/2016		1,111		21	%		48	$	5.4
17. AMPARAN 6-20-22 1H (4)	Lower Meramec	8/10/2016		515		7	%		42	$	5.0
18. DRINNON 32-18-17 1H	Upper Osage	9/6/2016		621		7	%		61	$	6.9
19. SPORTSMAN 3-18-16 1H	Lower Meramec	9/20/2016		1,375		44	%		44	$	4.4
20. MCCORMICK 3-19-20 1H	Upper Osage	10/2/2016		988		27	%		53	$	6.0
21. STORY 23-21-20 1H	Upper Osage	10/3/2016		855		44	%		54	$	5.1
22. LINDA 19-20-19 1H	Upper Osage	11/8/2016		1,202		38	%		50	$	5.0
23. MCALARY 25-19-20 1H	Lower Osage	11/22/2016		806		26	%		72	$	7.0
24. RUSSELL 17-19-17 1H	Upper Meramec	11/23/2016		1,125		62	%		41	$	6.0
25. KROWS 19-19-17 1H	Lower Meramec	12/14/2016		1,399		46	%		41	$	5.8
26. MAIN 3-19-19 1H	Upper Osage	1/17/2017		382		29	%		71	$	7.7
27. MERLE 32-19-17 1H	Upper Meramec	1/31/2017		746		54	%		28	$	4.7
28. CRITES 13-20-20 1H	Upper Osage	2/1/2017		1,261		53	%		45	$	5.8
29. MARILYN 14-20-20 1H	Upper Osage	2/23/2017							38	$	4.8
30. FRED 4-19-17 1H	Upper Osage	3/6/2017							52
31. BRUCE 16-20-20 1H	Middle Meramec	3/13/2017							42
32. RAPP 1-19-18 1H	Upper Meramec	3/23/2017							42
33. HEDGES 6-19-17 1H	Upper Osage	(5)							48
34. EARL 30-19-17 1H	Lower Meramec	(6)							29
35. SEAL TRUST 29-19-16 1H	Upper Osage	(6)							23
36. BROWN TRUST 31-20-17 1H	Upper Meramec	(7)
37. ELAINE 12/13-19-18 1H	Upper Meramec - 2 Mile	(7)
38. AMANDA 13-19-17 1H	Lower Meramec	(7)
39. ROY 26-19-18 1H	Lower Meramec	(7)

(1)	The peak initial production data is determined by selecting the maximum 30-day rolling averages for days that had recorded production.

(2)	Shown on a combined basis for oil, natural gas and NGLs.

(3)	Cost data reflects field estimates for wells 26 through 29. Certain high-cost wells reflect certain additional costs related to data acquisition methods such as drilling pilot holes and taking core samples, and in some cases, significant mechanical issues.

(4)	Plugged prior to December 31, 2016 due to a tool being lost in the well.

(5)	Well is in flowback.

(6)	Wells are waiting on completion.

(7)	Wells are being drilled.

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focusing our wellbore targeting with the assistance of 3D seismic data;

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improving drilling efficiencies;

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utilizing advanced completion techniques;

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increasing lateral lengths from one-mile to two-mile laterals; and

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maximizing efficiencies in field development.

In addition, industry activity in and around our acreage block continues to intensify. In this regard, on February 21, 2017, we entered into a farmout agreement with Chesapeake Exploration, L.L.C. (“Chesapeake Exploration”), whereby Chesapeake Exploration has committed to drill multiple wells in an area in our NW Stack acreage outside of our existing 3D seismic shoot. The farmout covers an area that would permit Chesapeake Exploration to earn up to approximately 6,000 net leasehold acres under a 90-day continuous drilling obligation. To earn all of the farmout acreage, Chesapeake Exploration would have to drill a total of 15 wells. We will retain an overriding royalty interest of approximately 1.25% on all leases assigned and a 10% carried working interest in each earning well drilled by Chesapeake Exploration. We will also retain the right to drill offset units from each earning well drilled by Chesapeake Exploration in the farmout area.

Legacy Producing Properties

Our legacy producing properties in the Anadarko Basin are in the following areas: the Stiles Ranch Field located in Wheeler County, Texas in the Granite Wash play (“Stiles Ranch”); the Verden Field located in Caddo and Grady Counties, Oklahoma (“Verden”); the Mississippian formation in Barber, Harper and Reno Counties, Kansas (“Kansas”); and the Mocane-Laverne Field in Beaver, Harper and Ellis Counties, Oklahoma (“Mocane-Laverne”). For the three months ended December 31, 2016, the average net production from these legacy producing properties was 18.2 MBoe/d, of which 15% was oil, 57% was natural gas and 28% was NGLs. For the year ended December 31, 2016, the average net production from these legacy producing properties was 21.2 MBoe/d, of which 19% was oil, 53% was natural gas and 28% was NGLs. We believe economic development potential exists in our legacy producing properties, as these properties are located in areas that are being actively developed by industry peers with successful results.

Stack and are generally characterized as having long-lived, predictable production profiles. As of December 31, 2016, we owned approximately 9,080 net acres in Stiles Ranch that were all held by production from 223 operated and 10 non-operated gross wells. As of December 31, 2016, our acreage position in Verden consisted of approximately 15,795 net acres that were all held by production from 117 operated and 52 non-operated gross wells. As of December 31, 2016, our acreage position in Kansas consisted of approximately 112,435 net acres, approximately 39,000 of which were held by production from 78 operated gross wells. As of December 31, 2016, our acreage position in Mocane-Laverne consisted of approximately 87,260 net acres that were all held by production from 312 operated and 130 non-operated gross wells.

Proved Reserves

The following tables provide summary information regarding our proved reserves as of December 31, 2016 and our production for the three months ended December 31, 2016. The reserve estimates attributable to our assets as of December 31, 2016 are based on reserve reports prepared by Ryder Scott Company, L.P. (“Ryder Scott”), independent petroleum engineers, in accordance with the SEC’s rule regarding reserve reporting currently in effect.


	SEC (1)
	Estimated Total Proved Reserves as of December 31, 2016														Net Production for the Three Months Ended December 31, 2016 (MBoe/d)
Project Area	Oil (MMBbls)		NGLs (MMBbls)		Natural Gas (Bcf)		Total (MMBoe)		% Oil		% NGLs		% Natural Gas
NW Stack		4.5		5.5		107.8		28.0		16%		20%		64%		5.1
Stiles Ranch		4.6		15.2		123.2		40.3		11%		38%		51%		10.3
Verden		0.5		0.1		63.3		11.1		4%		1%		95%		2.1
Kansas		8.1		5.0		72.1		25.2		32%		20%		48%		4.1
Mocane-Laverne		0.4		1.3		19.9		5.0		8%		26%		66%		1.7

Total (2)		18.0		27.1		386.2		109.5		16%		25%		59%		23.3

(1)

(2)	Totals may not sum or recalculate due to rounding.


	NYMEX (1)
	Estimated Total Proved Reserves as of December 31, 2016
Project Area	Oil (MMBbls)		NGLs (MMBbls)		Natural Gas (Bcf)		Total (MMBoe)		% Oil		% NGLs		% Natural Gas
NW Stack		4.9		6.0		118.5		30.6		16%		20%		64%
Stiles Ranch		4.9		17.4		141.0		45.8		11%		38%		51%
Verden		0.5		0.1		66.2		11.6		`4%		1%		95%
Kansas		8.8		5.6		79.6		27.6		32%		20%		48%
Mocane-Laverne		0.4		1.8		27.4		6.8		7%		26%		67%

Total (2)		19.5		30.8		432.6		122.5		16%		25%		59%

(1)

Our NYMEX reserves were determined using index prices for oil and natural gas, without giving effect to derivative transactions. The average future prices for benchmark commodities used in determining our NYMEX reserves were $56.19/Bbl for 2017, $56.59/Bbl for 2018, $56.10/Bbl for 2019, $56.05/Bbl for 2020, $56.21/Bbl for 2021, $56.51/Bbl for 2022, $57.23/Bbl for 2023, $57.70/Bbl for 2024, $58.03/Bbl for 2025, and $58.10/Bbl for 2026 and thereafter for oil and $3.61/Mcf for 2017, $3.14/Mcf for 2018, $2.87/Mcf for 2019, $2.88/Mcf for 2020, $2.90/Mcf for 2021, $2.93/Mcf for 2022, $3.02/Mcf for 2023, $3.16/Mcf for 2024, $3.31/Mcf for 2025, and $3.68/Mcf for 2026 and thereafter for natural gas.NGLs pricing used in determining our NYMEX reserves were approximately 35% of future oil prices.

(2)	Totals may not sum or recalculate due to rounding.

Drilling Inventory

In this prospectus, our “identified horizontal drilling locations” in the NW Stack refer to identified horizontal drilling locations that have been adjusted using the above methodology and are presented on a single-mile lateral basis. As of December 31, 2016, we had a drilling inventory consisting of 5,849 gross (2,546 net) identified horizontal drilling locations in the NW Stack. Of such inventory, 558 gross (422 net) operated identified horizontal drilling locations are within the Seiling 3D seismic outline and 1,472 gross (1,050 net) operated identified horizontal drilling locations are captured within the outline of the Moscow Flats 3D seismic shoot that is currently

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underway. The remaining 748 gross (519 net) operated identified horizontal drilling locations are outside of any current or planned 3D seismic shoots.


	NW Stack Horizontal Drilling Locations(1)(2)(3)(4)(5)
						Gross Locations						Net Locations
	Net Acres		Average Working Interest			Oil		Gas Condensate		Total		Oil		Gas Condensate		Total		Operated Inventory Life (6)
Operated – Seiling 3D		33,177		76	%		341		217		558		265		157		422		11
Operated – Moscow Flats 3D		80,860		71	%		1,008		464		1,472		714		335		1,050		28
Operated – Outside 3D		39,935		69	%		144		604		748		105		414		519		14

Total Operated		153,972		72	%		1,493		1,285		2,778		1,084		906		1,990		53
Non-Operated		42,733		18	%		1,608		1,463		3,071		283		273		556

Total NW Stack		196,705		44	%		3,101		2,748		5,849		1,367		1,179		2,546

(1)

We have estimated our drilling locations based on well spacing assumptions and upon the evaluation of our horizontal drilling results and those of other operators in our area, combined with our interpretation of available geologic and engineering data. Please read “—Our Properties” for more information regarding the process and criteria through which these drilling locations were identified.

(2)

(3)	Our total identified horizontal drilling locations include 48 gross (26 net) locations associated with proved undeveloped reserves as of December 31, 2016 in the NW Stack.

(4)	Includes locations targeting the Upper Meramec, Middle Meramec, Lower Meramec, Upper Osage and Lower Osage benches. Please read “—Our Properties—NW Stack” for a description of these benches.

(5)	Totals may not sum or recalculate due to rounding.

(6)	We have estimated inventory life years for our operated locations based on total gross locations and our 2017 development plan to drill 39 gross horizontal wells (approximately 26 of which we anticipate to be

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single-mile laterals and 13 of which we anticipate to be two-mile laterals, which equates to 52 single-mile equivalent wells).

Business Strategies

Our primary objective is to maximize stockholder value across business cycles by pursuing the following strategies:

•

Focus on advanced operational, drilling and completion techniques that are expected to result in improved capital efficiencies and increased well returns. As we accelerate the development of our NW Stack acreage position, our management and technical teams will focus on utilizing advanced operational, drilling and completion techniques, in conjunction with 3D seismic data, to maximize hydrocarbon recovery per well. While maximizing per-well recovery, we expect to minimize our capital and operating cost per Boe, with the ultimate objective of maximizing returns of our large drilling inventory. In order to achieve these objectives, we intend to:

•

maximize well production and hydrocarbon recovery through advanced drilling, completion and production methods such as optimizing wellbore targeting, lateral lengths and completion design; and

•

minimize the capital cost per Boe of drilling and completing horizontal wells through knowledge of the target formations, optimization of drilling techniques to reduce cycle times and engagement in best cost management practices.

•

Take advantage of our balanced acreage position, spanning the oil and natural gas condensate windows of the NW Stack, providing us optionality around our drilling plan, capital program and commodity mix. Our contiguous acreage position spans a highly productive area across the over-pressured oil and natural gas condensate windows of the NW Stack. We believe our balanced mix of oil and natural gas condensate locations provides us with the flexibility to adjust our drilling program and capital expenditure plans in response to the commodity price environment. The natural gas condensate we produce has a high Btu content that typically ranges from 1,100 to 1,300 Btu per standard cubic foot, further enhancing economics of our production as compared to dry natural gas.

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We believe this diversity of commodity exposure and our ability to modify the development plan and the associated capital expenditures help mitigate commodity price exposure.

•

Our Competitive Strengths

We believe the following strengths will allow us to successfully execute on our business strategies:

•

Extensive, contiguous and operated acreage position concentrated in the NW Stack that is expected to generate attractive single-well rates of return. As of December 31, 2016, we operated 78% of our approximately 200,000 net acres in the NW Stack, which we believe to be emerging as one of North America’s most prolific, oil and natural gas condensate plays. As evidenced by initial production rates and estimated EURs per well on our 33 Tapstone-operated horizontal wells, we believe the returns from our wells in the NW Stack are competitive with returns generated among other leading plays across the lower 48 states. We operate the majority of our position within the NW Stack, which provides us with control and flexibility to adjust the pace of our development program, as well as the length of our laterals and our drilling and completion techniques, in order to optimize our capital investments.

•

Our acreage position in the NW Stack has been substantially delineated across multiple productive benches in which we have identified a multi-decade balanced inventory of drilling locations. We have substantially delineated our NW Stack acreage through extensive technical evaluation, including Tapstone-operated horizontal wells, over 50 horizontal wells drilled by offset operators, over 900 existing vertical wells drilled on or around our acreage and 2D and 3D seismic data available in the area. As of December 31, 2016, we had identified over 2,700 gross operated horizontal drilling locations in the NW Stack, providing us with a multi-decade drilling inventory. Our drilling activity has been and will continue to be focused on the oil and natural gas condensate windows of the NW Stack, which is expected to produce attractive single-well economics. Additionally, as we accelerate the development of our acreage position, we are optimizing our development plan in order to maximize the value of our resource potential. As of March 23, 2017, we operated four rigs deployed across our acreage position and intend to increase our rig count to a total of six operated rigs by the end of 2017.

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•

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(v) maximizing efficiencies in field development. Members of our management team have previously held positions with major independent oil and natural gas companies, including Continental Resources, Inc., Chesapeake Energy Corporation and SandRidge Energy, Inc.

•

Recent Developments

Amendment to Credit Facility

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Our Properties

Anadarko Basin. The Anadarko Basin, which covers approximately 56,000 square miles across portions of Texas, Colorado, Kansas and Oklahoma, is one of the most prolific and largest onshore producing oil and natural gas basins in the United States, featuring multiple producing horizons and extensive well control demonstrated over seven decades of development. The formations we target are generally characterized by oil and natural gas condensate content, extensive production histories, long-lived reserves, high drilling success rates and attractive production rates. We focus on formations in our operating areas that we believe offer significant development and acquisition opportunities and to which we can apply our technical experience and operational expertise to increase proved reserves and production to deliver compelling economic rates of return.

The map below depicts the location of our properties as of December 31, 2016, which include working interests in approximately 567,444 gross (421,275 net) acres, all of which are located in the Anadarko Basin in Oklahoma, Texas and Kansas.

LOGO

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The following table summarizes our acreage by project area as of December 31, 2016.


	Gross		Net
Project Area:
NW Stack		296,730		196,705
Stiles Ranch		10,564		9,080
Verden		39,680		15,795
Kansas		115,951		112,435
Mocane-Laverne		104,518		87,260

Total		567,443		421,274

We refer to gross and net acreage where we are designated as operator or expect to be designated as operator based on the size of our working interest relative to other working interest owners as “our operated acreage” or acreage we “operate” in this prospectus. We have an average working interest of approximately 84% in all of our operated acreage, which includes approximately 70% of our total net acreage. This operational control gives us flexibility in development strategy and pace. As of March 23, 2017, we operated four rigs deployed across our acreage position and intend to increase our operated rig count to a total of six operated rigs by the end of 2017. During the years ended December 31, 2016 and 2015, we operated an average of 3.5 and 3 rigs across all of our properties, respectively, and placed 25 and 40 horizontal wells on production, respectively. Our development drilling plan is comprised exclusively of horizontal drilling with an ongoing focus on reducing drilling times, optimizing completions and lowering drilling costs.

While economic development potential exists in Kansas, Stiles Ranch and Verden, the focus of our drilling program is on deploying our capital in the NW Stack. To date, our NW Stack drilling program has focused on delineating our acreage both geologically and geographically. We intend to adjust our focus to the development of our acreage in the NW Stack by (i) transitioning away from our delineation phase, (ii) optimized wellbore targeting based on 3D seismic data, (iii) utilizing advanced completion techniques, (iv) increasing lateral lengths and (v) maximizing efficiencies in field development.

The effective execution of completion design, target identification and refined geosteering are the predominant factors that dictate relative well performance in an area or zone. In developing our acreage in the NW Stack, we intend to pursue a strategy that includes methodical adjustments of completion parameters, experimentation of different designs on wells with similar rock characteristics and constant monitoring and re-evaluation of results that ultimately tailor completions to the conditions specific to an area or zone. We expect that our focus on improving our completion techniques will serve to further increase stockholder value.

As of December 31, 2016, our total estimated proved reserves net to our interest in our properties were approximately 109,546 MBoe, of which 59.9% were classified as proved developed (of which 98.9% are proved developed producing and 1.1% proved developed non-producing). Our proved reserves are generally characterized as long-lived, with predictable production profiles and are estimated to contain 16.5% oil, 58.8% natural gas and 24.8% NGLs. As of December 31, 2016, the standardized measure and PV-10 of our total estimated proved reserves, in accordance with the SEC’s rule regarding reserve reporting currently in effect was $320.7 million and $322.7 million, respectively. Please read “Selected Historical Consolidated Financial Data—Non-GAAP Financial Measures—PV-10”.

For the year ended December 31, 2016, our average net daily production was 26,850 Boe/d (approximately 19% oil, 55% natural gas and 26% NGLs). As of December 31, 2016, we produced from 290 gross horizontal wells, 254 of which we operated (75 of which we drilled and completed) and 676 gross vertical wells, 500 of which we operated.

During the year ended December 31, 2016, 35 gross (22.8 net) wells were placed on production on our acreage. All of these wells were horizontal wells.

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As of December 31, 2016, we had identified 6,337 gross (2,912 net) horizontal drilling locations on our acreage. As of December 31, 2016, 119 gross (93 net) horizontal drilling locations were associated with proved undeveloped reserves across all of our acreage. We continue to improve our well economics as we begin to drill longer laterals. In this prospectus, we define identified gross drilling locations as locations specifically identified by management as an estimation of our multi-year drilling activities on existing acreage, based on an evaluation of applicable geologic and engineering data. We have estimated our identified horizontal drilling locations based on well spacing assumptions and upon the evaluation of our horizontal drilling results as well as those of other operators in our area, along with our interpretation of available geologic and engineering data. In particular, we have analyzed and interpreted open-hole logs, whole and sidewall core data, production data and drill cuttings that were acquired through our horizontal drilling program. The horizontal drilling locations for which we actually drill wells will ultimately depend upon the availability of capital, regulatory approvals, oil and natural gas prices, operating costs, actual drilling results and other factors.

NW Stack. Our approximately 200,000 net acres in the NW Stack consist of large, contiguous blocks in the adjacent Oklahoma counties of Dewey, Woodward, Ellis and Major that we acquired through our organic leasing program. The NW Stack is trending along the basin ramp from the Anadarko Shelf to the Anadarko Deep Basin and is characterized by brittle lithology that is susceptible to fracturing. We believe the geological characteristics and structural nature of the NW Stack have resulted in attractive well results across our acreage position in the NW Stack. The NW Stack reservoir depths range from approximately 9,000 to 13,000 feet and are characterized by higher than normal reservoir pressures, which result in high production deliverability and attractive single-well rates of return.

Additionally, the NW Stack is characterized as having multiple stacked pay carbonate reservoir targets, and we are focused on developing the Upper, Middle and Lower benches in the Meramec interval and the Upper and Lower benches in the Osage interval, with a gross thickness of 1,000 to 1,500 feet across each of these five stacked benches. We believe this layered nature presents significant development potential with sizable drilling inventory. Within the NW Stack, the Meramec interval has a thickness range of 700 to 1,000 feet and is characterized by a lithology that is conducive for reduced drilling times when compared to deeper targets in the Mississippian formation. The top of the Meramec interval ranges from approximately 9,000 feet to 11,500 feet. The Osage interval has a thickness that ranges from 300 to 500 feet and the carbonate section is more brittle in nature, providing increased porosity and permeability. The top of the Osage interval ranges from approximately 10,000 feet to 13,000 feet.

As of December 31, 2016, we had 39 gross (21.4 net) horizontal producing wells in the NW Stack with an average working interest of 54.8%, of which we operated 24 gross (21.0 net) wells with an average working interest of 87.7%. Our NW Stack properties contained 28.0 MMBoe of estimated net proved reserves as of December 31, 2016, approximately 16% of which were oil, 64% of which were natural gas and 20% of which were NGLs, and generated an average daily net production of 5,634 Boe/d for the year ended December 31, 2016. We have successfully tested each of the five benches that we have identified over 40 miles east to west and 20 miles north to south across our acreage position in the NW Stack. As of December 31, 2016, our NW Stack properties accounted for approximately 19.8% of the standardized measure of our total estimated proved reserves. A large portion of our leases in the NW Stack have three-year primary terms with optional two year extensions or contractual rights to renew, giving us ample optionality into 2020. As of December 31, 2016, approximately 21,000 net acres in our NW Stack acreage position were held by production. As of December 31, 2016, we had identified 5,849 gross (2,546 net) horizontal drilling locations in the NW Stack. Of these locations, 5% are attributable to acreage that is currently held by production. As of December 31, 2016, 48 gross (26 net) horizontal drilling locations were associated with proved undeveloped reserves in the NW Stack. We plan to drill 39 gross (31.2 net) horizontal wells in the NW Stack in 2017, at an estimated cost to us of approximately $205 million.

Stiles Ranch. The Stiles Ranch field, located in Wheeler County, Texas, is an established field in the Granite Wash. The Granite Wash is a tight sand play located in the Texas panhandle and western Oklahoma. The

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Granite Wash is characterized by multiple target horizons, extensive production histories, long-lived reserves, high drilling success rates and high initial production rates.

As of December 31, 2016, we controlled approximately 9,080 net acres in Stiles Ranch that are all held by production and had 233 gross (192.2 net) producing wells with an average working interest of 82.5%, of which we operated 223 gross (191.5 net) wells with an average working interest of 85.9%. Our Stiles Ranch properties contained 40.3 MMBoe of estimated net proved reserves as of December 31, 2016, approximately 11% of which were oil, 51% of which were natural gas and 38% of which were NGLs, and generated an average daily net production of 11,776 and 15,878 Boe/d for the years ended December 31, 2016 and 2015, respectively. As of December 31, 2016, our Stiles Ranch properties accounted for approximately 32.2% of the standardized measure of our total estimated proved reserves. As of December 31, 2016, we had identified 113 gross (100 net) horizontal drilling locations in Stiles Ranch. All of these locations are attributable to acreage that is currently held by production. As of December 31, 2016, 17 gross (15 net) horizontal drilling locations were associated with proved undeveloped reserves in Stiles Ranch.

Verden. Our Verden acreage is located in Caddo and Grady Counties in western Oklahoma and has produced gas from multiple intervals of the Springer formation. Currently, there is ongoing delineation activity by our peers in Verden with highly encouraging results from a series of shallow intervals in the Hoxbar formation oil reservoirs, at a depth of approximately 11,000 feet.

As of December 31, 2016, we controlled approximately 15,795 net acres in the Verden that are all held by production and had 169 gross (78.6 net) producing wells with an average working interest of 46.5%, of which we operated 117 gross (71.1 net) wells with an average working interest of 60.7%. Our Verden properties contained 11.1 MMBoe of estimated net proved reserves as of December 31, 2016, approximately 4% of which were oil, 95% of which were natural gas and 1% of which were NGLs, and generated an average daily net production of 2,179 Boe/d and 2,308 Boe/d for the years ended December 31, 2016 and 2015, respectively. As of December 31, 2016, our Verden properties accounted for approximately 13.0% of the standardized measure of our total estimated proved reserves. As of December 31, 2016, we had identified 144 gross (54 net) horizontal drilling locations in Verden. All of these locations are attributable to acreage that is currently held by production. As of December 31, 2016, 2 gross (0 net) horizontal drilling locations were associated with proved undeveloped reserves in Verden.

Kansas. Our Kansas acreage is located in Barber, Harper and Reno Counties in south-central Kansas, where the Mississippian formation is the main target for exploration and development within the Anadarko Basin. Our Kansas acreage is situated on the Anadarko Shelf, which is located in northern Oklahoma and southern Kansas and is an expansive hydrocarbon system consisting of carbonate rocks (limestone, dolomite and chert) that have primary and secondary porosity and permeability. The top of this formation is encountered between approximately 4,000 and 5,000 feet and lies stratigraphically above the Devonian-aged Woodford Shale and below the Pennsylvanian-aged shales. The Mississippian formation can reach up to 500 feet in gross thickness and has a targeted interval of up to 150 feet in thickness.

As of December 31, 2016, we controlled approximately 112,435 net acres in Kansas, approximately 39,000 of which were held by production, and had 78 gross (78 net) producing wells with 100% working interests, all of which we operated. Our Kansas properties contained 25.2 MMBoe of estimated net proved reserves as of December 31, 2016, approximately 32% of which were oil, 48% of which were natural gas and 20% of which were NGLs, and generated an average daily net production of 5,408 Boe/d and 5,097 Boe/d for the years ended December 31, 2016 and 2015, respectively. As of December 31, 2016, our Kansas properties accounted for approximately 31.6% of the standardized measure of our total estimated proved reserves. As of December 31, 2016, we had identified 231 gross (212 net) horizontal drilling locations in Kansas. Approximately 46% of these locations are attributable to acreage that is currently held by production. As of December 31, 2016, 52 gross (51 net) horizontal drilling locations were associated with proved undeveloped reserves in Kansas.

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Mocane-Laverne. As of December 31, 2016, we controlled approximately 87,260 net acres in the Mocane-Laverne that are all held by production and had 442 gross (290.0 net) producing wells with an average working interest of 65.6%, of which we operated 312 gross (261.2 net) wells with an average working interest of 83.7%. Our Mocane-Laverne properties contained 5.0 MMBoe of estimated net proved reserves as of December 31, 2016, approximately 8% of which were oil, 66% of which were natural gas and 26% of which were NGLs, and generated an average daily net production of 1,842 Boe/d and 1,872 Boe/d for the years ended December 31, 2016 and 2015, respectively. As of December 31, 2016, our Mocane-Laverne properties accounted for approximately 3.4% of the standardized measure of our total estimated proved reserves.

Oil and Natural Gas Data

Proved Reserves

Evaluation of Proved Reserves. Our proved reserve estimates as of December 31, 2016 were prepared by Ryder Scott, our independent petroleum engineers. Within Ryder Scott, the technical persons primarily responsible for preparing the estimates set forth in the Ryder Scott proved reserve reports incorporated herein are Daniel R. Olds, Eric T. Nelson and Stuart L. Filler. Mr. Olds, an employee of Ryder Scott since 2001, is a Managing Senior Vice President and also serves as an Engineering Group Coordinator responsible for coordinating and supervising Ryder Scott’s staff and consulting engineers in ongoing reservoir evaluation studies worldwide. He is also a member of Ryder Scott’s board of directors. Before joining Ryder Scott, Mr. Olds served in a number of engineering and evaluation positions with PricewaterhouseCoopers, Wintershall Oil and Gas Company and Cities Service Oil Company. Mr. Olds earned a Bachelor of Science degree in Petroleum Engineering from West Virginia University in 1981, a Master of Business Administration from the University of Houston in 1991 and is a licensed Professional Engineer in the State of Texas. He is also a member of the Society of Petroleum Evaluation Engineers and the Society of Petroleum Engineers and has been licensed by the Texas Board of Professional Engineers (the “TBPE”).

Based on Mr. Olds’ educational background, professional training and more than 35 years of practical experience in the estimation and evaluation of petroleum reserves, Mr. Olds 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 (the “Standards”) promulgated by the Society of Petroleum Engineers on February 19, 2007.

Mr. Nelson, an employee of Ryder Scott since 2005, is a Managing Senior Vice President responsible for ongoing reservoir evaluation studies worldwide. Before joining Ryder Scott, Mr. Nelson served in a number of engineering positions with Exxon Mobil Corporation. Mr. Nelson earned a Bachelor of Science degree in Chemical Engineering from the University of Tulsa in 2002 (summa cum laude) and a Master of Business Administration from the University of Texas in 2007 (Dean’s Award). He is a licensed Professional Engineer in the State of Texas, a member of the Society of Petroleum Engineers and has been licensed by the TBPE.

Based on Mr. Nelson’s educational background, professional training and more than eleven years of practical experience in the estimation and evaluation of petroleum reserves, Mr. Nelson has attained the professional qualifications as a Reserves Estimator set forth in Article III of the Standards promulgated by the Society of Petroleum Engineers.

Mr. Filler, an employee of Ryder Scott since 2014, is a Vice President and also serves as Project Coordinator, responsible for coordinating and supervising staff and consulting engineers in ongoing reservoir evaluation studies worldwide. Before joining Ryder Scott, Mr. Filler served in a number of engineering positions with Golden Engineering, Core Laboratories, CSX Oil and Gas, Energy Development Corporation, Devon Energy Corporation, Southwestern Energy Company and HighMount Exploration and Production. Mr. Filler earned a Bachelor of Science degree in Petroleum Engineering from the Texas A&M University in 1974, a Master of Science degree from the University of Houston – University Park in 1986 and completed course work

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and qualifying examinations at the University of Texas. He is a licensed Professional Engineer in the State of Texas, a member and past president of the Society of Petroleum Evaluation Engineers, an associate member of the American Association of Petroleum Geologists, a member of the Society of Petroleum Engineers and has been licensed by the TBPE.

Based on Mr. Filler’s educational background, professional training and more than 39 years of practical experience in the estimation and evaluation of petroleum reserves, Mr. Filler has attained the professional qualifications as a Reserves Estimator set forth in Article III of the Standards promulgated by the Society of Petroleum Engineers.

Ryder Scott does not own an interest in any of our properties, nor is it employed by us on a contingent basis. Copies of Ryder Scott’s proved reserve reports as of December 31, 2016 and beginning January 1, 2017 are included as exhibits to the registration statement of which this prospectus forms a part.

Our proved reserve estimates as of December 31, 2015 were prepared by Lee Keeling and Associates, Inc. (“Lee Keeling”), our independent petroleum engineers. Within Lee Keeling, the technical person primarily responsible for preparing the estimates set forth in the Lee Keeling summary reserve reports incorporated herein is John R. Wheeler. Mr. Wheeler has been with Lee Keeling since 2001 and became the firm’s Vice President in 2011. Mr. Wheeler graduated from the University of Oklahoma with a Bachelor of Science Degree in Geology in 1984 and from the University of Tulsa with a Master of Science Degree in Geology in 1989 and has over 25 years of oil and natural gas experience. Mr. Wheeler meets or exceeds the education, training and experience requirements outlined in the Standards promulgated by the Society of Petroleum Engineers and is proficient in applying industry standard practices to engineering evaluations as well as applying SEC and other industry reserves definitions and guidelines. Lee Keeling does not own an interest in any of our properties, nor is it employed by us on a contingent basis. A copy of Lee Keeling’s proved reserve report as of December 31, 2015 is included as an exhibit to the registration statement of which this prospectus forms a part.

We maintain an internal staff of petroleum engineers and geoscience professionals who work closely with our independent petroleum engineers to ensure the integrity, accuracy and timeliness of the data used to calculate our proved reserves. Our internal technical team members meet periodically with our independent petroleum engineers during the period covered by the proved reserve report to discuss the assumptions and methods used in the proved reserve estimation process. We provide historical information to our independent petroleum engineers for our properties, such as ownership interests, oil and natural gas production, well test data, commodity prices and operating and development costs. Roger A. Harrod, our Senior Reservoir Engineer, is primarily responsible for overseeing the preparation of all of our reserve estimates. Mr. Harrod is a reservoir engineer with over 20 years of reservoir and operations experience.

The preparation of our proved reserve estimates were completed in accordance with our internal control procedures. These procedures, which are intended to ensure reliability of reserve estimations, include the following:

•

review and verification of historical production data, which data is based on actual production as reported by us;

•

verification of property ownership by our land department;

•

review and verification of lease operating statements;

•

review of reserve estimates by Mr. Harrod or under his direct supervision; and

•

review by our Chief Executive Officer of all of our reported proved reserves, including the review of all significant reserve changes and all new PUDs additions.

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Estimation of Proved Reserves. Under SEC rules, proved reserves are those quantities of oil and natural gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible. If deterministic methods are used, the SEC has defined reasonable certainty for proved reserves as a “high degree of confidence that the quantities will be recovered”. All of our proved reserves as of December 31, 2016 and 2015 were estimated using a deterministic method. The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and natural gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions set forth by the SEC’s regulations. The process of estimating the quantities of recoverable oil and natural gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods: (i) performance-based methods, (ii) volumetric-based methods and (iii) analogy. These methods may be used individually or in combination by the reserve evaluator in the process of estimating the quantities of reserves. Proved reserves for our properties were estimated by performance methods for the majority of our properties. Certain new producing properties with inadequate historical production data were forecast using analogy or a combination of methods. Non-producing reserve estimates, for developed and undeveloped properties, were forecast using analogy methods.

To estimate economically recoverable proved oil and natural gas reserves and related future net cash flows, our independent petroleum engineers each considered many factors and assumptions including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data that cannot be measured directly, economic criteria based on current costs and the SEC pricing requirements and forecasts of future production rates.

Under SEC rules, reasonable certainty can be established using techniques that have been proven effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that have been field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. To establish reasonable certainty with respect to our estimated proved reserves, the technologies and economic data used in the estimation of our proved reserves have been demonstrated to yield results with consistency and repeatability, and include production and well test data, downhole completion information, geologic data, electrical logs, radioactivity logs, core analyses, available seismic data and historical well cost and operating expense data.

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Summary of Reserves. The following table presents our estimated net proved reserves as of December 31, 2016 and 2015, based on the proved reserve reports as of such dates prepared by our independent petroleum engineers. A copy of each proved reserve report as of December 31, 2016 prepared by Ryder Scott and the reserve report as of December 31, 2015 prepared by Lee Keeling, respectively, with respect to our properties are included as exhibits to the registration statement of which this prospectus forms a part. All of our proved reserves are located in the United States.


	NYMEX			SEC
	As of December 31,
	2016 (1)			2016 (2)			2015 (3)
Proved Developed Reserves:
Oil (MBbls)		8,580			7,734			11,024
Natural gas (MMcf)		279,402			243,766			286,632
NGLs (MBbls)		20,244			17,266			21,146

Total (MBoe) (4)		75,391			65,628			79,942
Proved Undeveloped Reserves:
Oil (MBbls)		10,930			10,315			12,535
Natural gas (MMcf)		153,202			142,444			114,221
NGLs (MBbls)		10,598			9,863			9,058

Total (MBoe) (4)		47,062			43,919			40,629
Total Proved Reserves:
Oil (MBbls)		19,510			18,049			23,559
Natural gas (MMcf)		432,604			386,210			400,853
NGLs (MBbls)		30,842			27,129			30,203

Total (MBoe) (4)		122,453			109,546			120,571
Oil and Natural Gas Prices:
Oil – WTI posted price per Bbl		NA		$	42.75		$	50.28
Natural gas – Henry Hub spot price per MMBtu		NA		$	2.49		$	2.59
Standardized Measure (in thousands) (5)		—		$	320,720		$	472,686
Pro Forma Standardized Measure (in thousands) (6)		—		$	254,699		$	358,064
PV-10 (in thousands) (7)	$	670,334		$	322,682		$	475,416
Proved Developed % of Total Proved PV-10		67	%		79	%		83	%
Proved Undeveloped % of Total Proved PV-10		33	%		21	%		17	%

(1)

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of commodity prices as of a certain date and should not be confused with SEC prices. Investors should be careful to consider forward prices in addition to, and not as a substitute for, SEC prices, when considering our oil, natural gas and NGLs reserves.

(2)

Our estimated net proved reserves as of December 31, 2016 were determined using average first-day-of-the-month prices for the prior twelve months in accordance with SEC guidance. For oil and NGLs volumes, the average WTI posted price of $42.75 per barrel as of December 31, 2016, was adjusted for gravity, quality, local conditions, gathering, transportation fees and distance from market. For natural gas volumes, the average Henry Hub spot price of $2.49 per MMBtu as of December 31, 2016, was similarly adjusted for gravity, quality, local conditions, gathering, transportation fees and distance from market. All prices are held constant throughout the lives of the properties. The average adjusted product prices weighted by production over the remaining lives of the properties are $41.85 per barrel of oil, $14.94 per barrel of NGLs and $2.35 per Mcf of natural gas as of December 31, 2016.

(3)

Our estimated net proved reserves as of December 31, 2015 were determined using average first-day-of-the-month prices for the prior twelve months in accordance with SEC guidance. For oil and NGLs volumes, the average WTI posted price of $50.28 per barrel as of December 31, 2015, was adjusted for gravity, quality, local conditions, gathering, transportation fees and distance from market. For natural gas volumes, the average Henry Hub spot price of $2.587 per MMBtu as of December 31, 2015, was similarly adjusted for gravity, quality, local conditions, gathering, transportation fees and distance from market. All prices are held constant throughout the lives of the properties. The average adjusted product prices weighted by production over the remaining lives of the properties are $48.33 per barrel of oil, $16.59 per barrel of NGLs and $2.54 per Mcf of natural gas as of December 31, 2015.

(4)	Totals may not sum or recalculate due to rounding.

(5)

(6)

Following our corporate reorganization, we will be subject to U.S. federal, state and local income taxes and our future income taxes will be dependent on our future taxable income. As of December 31, 2016, we estimate that our pro forma standardized measure would have been approximately $255 million, as adjusted to give effect to the present value of approximately $66 million of future income taxes as a result of our being treated as a corporation for federal income tax purposes. We have assumed pro forma tax expense using a 38% blended corporate level federal and state tax rate. As of December 31, 2015, we estimate that our pro forma standardized measure would have been approximately $358 million, as adjusted to give effect to the present value of approximately $115 million of future income taxes as a result of our being treated as a corporation for federal income tax purposes.

(7)

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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

Reserve engineering is and must be recognized as a subjective process of estimating volumes of economically recoverable oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation. As a result, the estimates of different engineers often vary. In addition, the results of drilling, testing and production may justify revisions of such estimates. Accordingly, reserve estimates often differ from the quantities of oil and natural gas that are ultimately recovered. Estimates of economically recoverable oil and natural gas and of future net cash flows are based on a number of variables and assumptions, all of which may vary from actual results, including geologic interpretation, prices and future production rates and costs. Please read “Risk Factors” appearing elsewhere in this prospectus.

Additional information regarding our proved reserves can be found in the notes to our financial statements included elsewhere in this prospectus.

PUDs

As of December 31, 2016, our PUDs totaled 10,315 MBbls of oil, 142,445 MMcf of natural gas and 9,863 MBbls of NGLs, for a total of 43,918 MBoe. As of December 31, 2015, our PUDs totaled 12,535 MBbls of oil, 114,221 MMcf of natural gas and 9,058 MBbls of NGLs, for a total of 40,629 MBoe. PUDs will be converted from undeveloped to developed as the applicable wells are drilled and completed and begin production.

Of the 3,289 MBoe of PUDs we added during the year ended December 31, 2016, 20,810 MBoe were added due to extensions and discoveries, 15,968 MBoe were removed due to revisions of previous estimates and 1,554 MBoe were removed due to transfers to proved developed reserves. The 20,810 MBoe added due to extensions and discoveries resulted primarily from new proved undeveloped locations added as a result of the drilling and completion of new wells. The 15,968 MBoe removed due to revisions of previous estimates consists of 15,060 MBoe removed due to downward revisions of oil and natural gas prices, 795 MBoe removed due to changes in a previously adopted development plan and 7,806 MBoe removed due to well performance, offset by 7,693 MBoe added due to all other changes.

During the year ended December 31, 2016, we spent $7.3 million converting PUDs to proved developed reserves. During the year ended December 31, 2015, we spent $43.5 million converting PUDs to proved developed reserves.

All of our PUD drilling locations are scheduled to be drilled within five years of their initial booking. As of December 31, 2016, 0.6% of our total proved reserves were classified as proved developed non-producing.

Our reserve report for the year ended December 31, 2015 included capital costs of approximately $100.3 million for 2016, including approximately $38.2 million for PUDs. For the year ended December 31, 2016, we incurred approximately $131.5 million in drilling and completion capital expenditures. The variance between (A) each of (1) the amount scheduled in our reserve report to be spent on converting PUDs to proved developed reserves for 2016, (2) the amount we incurred on drilling and completion capital expenditures for the year ended December 31, 2016 and (3) the amount we spent converting PUDs to proved developed reserves for the year ended December 31, 2015 and (B) the amount we spent converting PUDs to proved developed reserves for the year ended December 31, 2016 is primarily related to our strategic shift in the first quarter of 2016 to focus our drilling program and related capital expenditures on the delineation of our NW Stack acreage. Our objective is to develop our PUDs within five years of initial booking. The final decision to proceed with the development of PUDs is based on a comprehensive analysis of multiple factors, including but not limited to projected cash flow, capital budget constraints, leasehold obligations, vertical and areal resource assessment and

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single-well rates of return, and is intended to align our development and capital expenditure plans to focus on projects that our management team believes will provide the greatest long-term returns for our stockholders. In the first quarter of 2016, we believed that shifting the focus of our drilling program from the development of our PUDs in our legacy producing properties to the comprehensive delineation of our NW Stack acreage would provide greater returns after initial delineation efforts identified the economic potential of the play. As a result of this strategic shift, we reallocated our rig activity and associated capital expenditures to the NW Stack primarily from Kansas and Stiles Ranch. As of December 31, 2015, six gross (four net) drilling locations in the NW Stack were PUD locations. Given the small number of booked PUD locations associated with our NW Stack acreage and our shift to focus our capital expenditures in the delineation of our NW Stack acreage, a limited amount of our drilling and completion capital expenditures on 2016 resulted in the conversion of PUDs to proved developed reserves. We believe that our strategic shift to the NW Stack and our subsequent efforts related thereto resulted in the successful delineation of each of the five benches that we have identified within the Meramec and Osage intervals. With the delineation of our NW Stack acreage complete, we remain committed to converting the PUDs we have booked to proved developed reserves and are now focused on optimizing our operational practices in order to enhance recoveries, reduce costs and increase single-well rates of return across our properties. As of December 31, 2016, we had a total of 119 gross (93 net) PUD locations across our properties consisting of 48 gross (26 net) locations in the NW Stack, 17 gross (15 net) locations in Stiles Ranch, two gross (0 net) locations in Verden and 52 gross (51 net) locations in Kansas. Based on our planned future drilling pace and capital budget allocated to the development of our PUDs, all of our gross PUD locations are scheduled to be developed within five years of their initial booking. As a result, we believe our decision to shift our capital expenditures from the development of our legacy producing properties to the delineation of the NW Stack in 2016 has not impacted our ability to convert PUDs to proved developed reserves within five years of their initial booking.

Our decision to proceed with the development of the PUDs at December 31, 2015 was based on the commodity prices reflected in our reserve report for the year ended December 31, 2015, which we believed was indicative of the commodity prices that we anticipated would be in effect at the time of the development of such locations. Specifically, our reserve report for the year ended December 31, 2015 estimated future net cash flows based on average adjusted product prices weighted by production over the remaining lives of the properties of $48.33 per barrel of oil, $16.59 per barrel of NGLs and $2.54 per Mcf of natural gas, in each case as of December 31, 2015. SEC first-day-of-the-month prices during the fourth quarter of 2015 and through February 24, 2016, the date of our reserve report for the year ended December 31, 2015, averaged $40.37 per barrel of oil and $2.21 per MMBtu of natural gas compared to twelve-month trailing average benchmark prices of $50.28 per barrel of oil (WTI posted) and $2.587 per MMBtu (Henry Hub spot). While the net reserves related to our PUDs are based on SEC pricing, the pace of development of our PUDs is based primarily on pricing observed from the commodities futures market (in particular NYMEX futures curve prices adjusted for field quality and location differentials) and management’s expectation of drilling and completion capital expenditures over the planned development period. As of February 24, 2016, the commodities futures market was such that the PUD development was still economically viable at the planned spud dates given in the reserve report for the year ended December 31, 2015, and the pace of development was also consistent with management’s expectation of drilling activity levels over the planned development period. Based on those assumptions and the commodities futures market, we believed that the PUDs reported would be economically viable.

At December 31, 2015, we believed there was a reasonable expectation that we would have the financing required to develop all of our undeveloped reserves disclosed as of December 31, 2015. The capital expenditures required to develop our undeveloped reserves as of December 31, 2015 over the remainder of the years in our reserve report were within the level of cash flows from operations that we expected to generate based on estimated average adjusted product prices weighted by production over the remaining lives of our properties of $48.33 per barrel of oil, $16.59 per barrel of NGLs and $2.54 per Mcf of natural gas. In addition, we had $47 million of available borrowing capacity under our credit facility at December 31, 2015 that could have been utilized to fund drilling expenses in the event of any unexpected shortfalls in cash flow from operations. Finally, we believed that we would have been able to access outside equity or debt financing from various financing sources, including GSO and third party financing sources, to develop our undeveloped reserves, if necessary.

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Our reserve report for the year ended December 31, 2016 included capital costs of approximately $104.2 million for 2017, including approximately $104.1 million for PUDs. Our decision to proceed with the development of the PUDs at December 31, 2016 was based on the commodity prices reflected in our reserve report for the year ended December 31, 2016, which we believed was indicative of the commodity prices that we anticipated would be in effect at the time of the development of such locations. Specifically, our reserve report for the year ended December 31, 2016 estimated future net cash flows based on average adjusted product prices weighted by production over the remaining lives of the properties of $41.85 per barrel of oil, $14.94 per barrel of NGLs and $2.35 per Mcf of natural gas, in each case as of December 31, 2016. SEC first-day-of-the-month prices during the fourth quarter of 2016 and through February 22, 2017, the date of our reserve report for the year ended December 31, 2016, averaged $50.71 per barrel of oil and $3.12 per MMBtu of natural gas compared to twelve-month trailing average benchmark prices of $42.75 per barrel of oil (WTI posted) and $2.49 per MMBtu (Henry Hub spot). While the net reserves related to our PUDs are based on SEC pricing, the pace of development of our PUDs is based primarily on pricing observed from the commodities futures market (in particular NYMEX futures curve prices adjusted for field quality and location differentials) and management’s expectation of drilling and completion capital expenditures over the planned development period. As of February 22, 2017, the commodities futures market was such that the PUD development was still economically viable at the planned spud dates given in the reserve report for the year ended December 31, 2016, and the pace of development was also consistent with management’s expectation of drilling activity levels over the planned development period. Based on those assumptions and the commodities futures market, we believed that the PUDs reported would be economically viable.

At December 31, 2016, we believed there was a reasonable expectation that we would have the financing required to develop all of our undeveloped reserves disclosed as of December 31, 2016. The capital expenditures required to develop our undeveloped reserves as of December 31, 2016 over the remainder of the years in our reserve report were within the level of cash flows from operations that we expected to generate based on estimated average adjusted product prices weighted by production over the remaining lives of our properties of $41.85 per barrel of oil, $14.94 per barrel of NGLs and $2.35 per Mcf of natural gas. In addition, we believed that we would have been able to access outside equity or debt financing from various financing sources, including GSO and third party financing sources, to develop our undeveloped reserves, if necessary. Finally, we intend to use a portion of the net proceeds we receive from this offering to repay the $ million of outstanding indebtedness under our credit facility, which will provide additional available borrowing capacity to develop our undeveloped reserves, and the remaining net proceeds to fund a portion of our 2017 capital program.

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Oil and Natural Gas Production Prices and Costs

Production and Price History

The following table sets forth information regarding net production of oil, natural gas and NGLs and certain price and cost information for each of the periods indicated:


	Year Ended December 31,
	2016		2015		2014
Production:
Oil (MBbls)		1,860		1,895		236
Natural gas (MMcf)		32,484		31,024		2,049
NGLs (MBbls)		2,553		2,476		117

Total (MBoe) (1)		9,827		9,542		694

Average sales price before impact of cash-settled derivatives:
Oil (per Bbl)	$	40.15	$	45.42	$	81.86
Natural gas (per Mcf)		2.29		2.63		3.97
NGLs (per Bbl)		14.17		12.68		39.14

Average (per Boe)	$	18.84	$	20.87	$	46.11

Average sales price after impact of cash-settled derivatives:
Oil (per Bbl)	$	48.40	$	63.84	$	88.36
Natural gas (per Mcf)		2.92		3.40		4.08
NGLs (per Bbl)		17.33		16.83		39.14

Average (per Boe)	$	23.31	$	28.10	$	48.65

Operating Expenses (per Boe):
Production expenses	$	7.40	$	6.79	$	9.58
Production taxes		0.44		0.87		2.03
Depreciation and depletion – oil and natural gas		6.09		8.40		11.51
Impairment of oil and natural gas properties		24.16		29.60		—
General and administrative (2)		1.51		1.70		19.70

Total operating expenses (per Boe)	$	39.59	$	47.36	$	42.83

(1)	Total may not sum or recalculate due to rounding.

(2)	General and administrative does not include additional expenses we will incur in the future as a result of being a public company.

Our Stiles Ranch, NW Stack and Kansas acreage were the only fields in which we operated that, as of December 31, 2016, each accounted for more than 15% of our total estimated proved reserves. Our Stiles Ranch acreage contained approximately 36.8% of our estimated proved reserves as of December 31, 2016. Production for the year ended December 31, 2016 was comprised of 570 MBbls of oil, 12,970 MMcf of natural gas and 1,578 MBbls of NGLs. Production for the year ended December 31, 2015 was comprised of 866 MBbls of oil, 17,251 MMcf of natural gas and 2,054 MBbls of NGLs. There was no production associated with Stiles Ranch in 2014. Our NW Stack acreage contained approximately 25.5% of our estimated proved reserves as of December 31, 2016. Production for the year ended December 31, 2016 was comprised of 407 MBbls of oil, 7,655 MMcf of natural gas and 379 MBbls of NGLs. Production for the year ended December 31, 2015 was comprised of 75 MBbls of oil, 1,197 MMcf of natural gas and 64 MBbls of NGLs. There was no production associated with NW Stack in 2014. Our Kansas acreage contained approximately 23.0% of our estimated proved reserves as of December 31, 2016. Production for the year ended December 31, 2016 was comprised of 782 MBbls of oil, 4,923 MMcf of natural gas and 377 MBbls of NGLs. Production for the year ended December 31, 2015 was comprised of 830 MBbls of oil, 4,605 MMcf of natural gas and 263 MBbls of NGLs. Production for the year ended December 31, 2014 was comprised of 236 MBbls of oil, 1,946 MMcf of natural gas and 117 MBbls of NGLs.

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Productive Wells

The following table sets forth information as of December 31, 2016 relating to the productive wells in which we owned a working interest as of that date. Gross wells are the total number of producing wells in which we have an interest, operated and non-operated, and net wells are the sum of our fractional working interests owned in gross wells.


	Oil				Natural Gas
	Gross		Net		Gross		Net
NW Stack
Operated		7		6.1		17		14.9
Non-operated		2		—		13		0.3

Total		9		6.1		30		15.2

Legacy Producing Properties
Operated		171		156.6		559		445.2
Non-operated		24		4.7		173		32.2

Total		195		161.3		732		477.4

Acreage

The following table sets forth information as of December 31, 2016, relating to our leasehold acreage. Developed acreage consists of acres spaced or assigned to productive wells and does not include undrilled acreage held by production under the terms of the lease. Undeveloped acreage is defined as acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil or natural gas, regardless of whether such acreage contains proved reserves.


	Developed Acreage				Undeveloped Acreage				Total Acreage
	Gross (1)		Net (2)		Gross (1)		Net (2)		Gross (1)		Net (2)
NW Stack		28,288		20,843		268,442		175,862		296,730		196,705
Legacy Producing Properties		193,658		150,493		77,055		74,077		270,713		224,570

Total		221,946		171,336		345,497		249,939		567,443		421,275

(1)

A gross acre is the portion of the total tract size of a lease from which a working interest is derived. The total number of gross acres is the total number of acres of all tracts described in all leases in which a working interest is owned. A working interest in a producing well is determined by the number of net acres expressed as percentage of the size of an established unit from which a well is producing.

(2)	The number of net acres is the sum of the fractional working interests owned in gross acres expressed as whole numbers and fractions thereof.

Certain of the leases comprising the undeveloped acreage set forth in the table above will expire at the end of their respective primary terms unless production from the leasehold acreage has been established prior to such date, in which event the lease will remain in effect until the cessation of production. All of the acreage in Stiles Ranch, Verden and Mocane-Lavern is developed acreage and is held by production. On our NW Stack and Kansas acreage, we have undeveloped leases which may expire unless production is established. In addition, in lieu of establishing production on a portion of the NW Stack and Kansas acreage, payments may be made pursuant to the provisions of certain of the leases to extend the term of such leases for an additional period of time. None of our horizontal drilling locations associated with proved undeveloped reserves are scheduled for drilling outside of a lease term or any extensions thereof.

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The following table sets forth the gross and net undeveloped acreage, as of December 31, 2016, that will expire over the next five years and beyond unless production is established within the spacing units covering the acreage or the lease is renewed or extended prior to the primary term expiration dates.


Project Area	2017				2018				2019				2020				2021 and Thereafter
Project Area	Gross		Net		Gross		Net		Gross		Net		Gross		Net		Gross		Net
NW Stack		44,443		28,287		140,406		88,043		82,615		58,415		619		200		1,645		916
Stiles Ranch		—		—		—		—		—		—		—		—		—		—
Verden		—		—		—		—		—		—		—		—		—		—
Kansas		62,119		60,348		8,296		8,296		4,889		4,889		—		—		—		—
Mocane-Laverne		—		—		—		—		—		—		—		—		—		—

Total		106,562		88,635		148,702		96,339		87,504		63,304		619		200		1,645		916

We intend to extend substantially all of the net acreage associated with our inventory of drilling locations through a combination of development drilling and leasehold extension and renewal payments. Of the 28,287 net acres expiring in the NW Stack in 2017 and the 88,043 net acres expiring in the NW Stack in 2018, we have the right to extend on 15,276 and 76,610 net acres, respectively, at a cost of approximately $10.3 million and $27.2 million, respectively. Of the 58,415 net acres expiring in the NW Stack in 2019, we have the right to extend on 43,119 net acres at a cost of approximately $15.6 million. With respect to the remaining 40,856 net acres for which we do not have an option to extend or renew in the NW Stack, 806 net acres are associated with 11 gross (3.9 net) wells of proved undeveloped reserves where the leases covering such expected wells will expire prior to our expected drilling date though we intend to negotiate extensions or renewals of such leases.

Of the 60,348 net acres expiring in Kansas in 2017 and the 8,296 net acres expiring in Kansas in 2018, we have options to extend on 6,495 and 2,119 net acres, respectively, at a cost of approximately $2 million and $0.4 million, respectively. Of the 4,889 net acres expiring in Kansas in 2019, we have an option to extend on 2,412 net acres at a cost of approximately $0.5 million. With respect to the remaining 62,507 net acres for which we do not have an option to extend or renew in Kansas, 3,201 net acres are associated with 8 gross ( 7.3 net) wells of proved undeveloped reserves where the leases covering such expected wells will expire prior to our expected drilling date, though we intend to negotiate extensions or renewals of such leases. We do not expect to renew the remaining expiring acreage in Kansas, none of which is associated with any proved undeveloped reserves. Please read “Risk Factors—Risks Related to Our Business—Certain of our undeveloped leasehold acreage is subject to leases that will expire over the next several years unless production is established on units containing the acreage, we pay the lessees option payments to extend the leases for an additional two years or the leases are renewed.”

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Drilling Results

The following table sets forth the drilling results of Tapstone-operated wells, as defined by wells having been placed on production, for the periods indicated. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation among the number of productive wells drilled, quantities of reserves found or economic value. Productive wells are those that produce, or are capable of producing, commercial quantities of hydrocarbons, regardless of whether they produce a reasonable rate of return. Dry wells are those that prove to be incapable of producing hydrocarbons in sufficient quantities to justify completion.


	Year Ended December 31,
	2016				2015				2014
	Gross		Net		Gross		Net		Gross		Net
NW Stack:
Exploratory Wells:
Productive (1)		16		14.2		6		5.2		—		—
Dry		—		—		—		—		—		—

Total Exploratory		16		14.2		6		5.2		—		—

Development Wells:
Productive (1)		3		2.6		—		—		—		—
Dry		—		—		—		—		—		—

Total Development		3		2.6		—		—		—		—

Total Wells:
Productive (1)		19		16.8		6		5.2		—		—
Dry		—		—		—		—		—		—

Total		19		16.8		6		5.2		—		—

Legacy Producing Properties:
Exploratory Wells:
Productive (1)		—		—		—		—		—		—
Dry		—		—		—		—		—		—

Total Exploratory		—		—		—		—		—		—

Development Wells:
Productive (1)		6		5.8		34		33.6		47		44.5
Dry		—		—		—		—		—		—

Total Development		6		5.8		34		33.6		47		44.5

Total Wells:
Productive (1)		6		5.8		34		33.6		47		44.5
Dry		—		—		—		—		—		—

Total		6		5.8		34		33.6		47		44.5

Combined Total		25		22.6		40		38.8		47		44.5

(1)	Although a well may be classified as productive upon completion, future changes in oil and natural gas prices, operating costs and production may result in the well becoming uneconomical, particularly exploratory wells where there is no production history.

As of March 23, 2017, we had 4 gross (3.0 net) wells in the process of being drilled and 2 gross (1.9 net) wells waiting on completion. Each of the wells is located in the NW Stack.

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Operations

General

As of December 31, 2016, we had an average working interest of approximately 84% in all of our operated acreage, which included approximately 70% of our total net acreage. As operator, we design and manage the development of our wells and supervise operation and maintenance activities on a day-to-day basis. Independent contractors engaged by us provide all the equipment and personnel associated with these activities. We employ petroleum engineers, geologists and land professionals who work to improve production rates, increase reserves, acquire properties, obtain permitting and lower the cost of operating our oil and natural gas properties.

Transportation and Marketing

During the acquisition or initial development of fields, we consider all gathering and delivery infrastructure in the vicinity. Our oil is collected from the wellhead to our tank batteries and then transported by the purchaser by truck or pipeline to another pipeline or a refinery. Our natural gas is transported from the wellhead to the purchaser’s meter and pipeline interconnection points.

The majority of our natural gas production in Stiles Ranch and Verden is dedicated to, gathered and processed by Enable under certain gas gathering and processing agreements. Under these agreements, we sell the residue gas at market prices pursuant to our right to take in-kind and the NGLs at market prices. With respect to our Stiles Ranch acreage, we are subject to two agreements, each dated January 2013, which together cover approximately 11,000 gross acres. With respect to our Verden acreage, we are subject to one agreement dated March 2008 and a second agreement dated July 2011, which together cover approximately 27,000 gross acres. In each of the agreements described herein, we are required to deliver to Enable for gathering and processing all of our natural gas production from the dedicated areas described in each such agreement. Under the 15-year agreement that pertains to approximately 10,000 gross acres of Stiles Ranch, if the volume of natural gas that we deliver from the dedicated area during any six-month period beginning on either January 1 or July 1 of each year is less than 95% of the volume of natural gas we delivered from such dedicated area during the immediately preceding six-month period (subject to certain exceptions), we are required to pay Enable for the difference at a rate of $0.40 per MMBtu we fail to deliver. This deficiency fee is Enable’s sole and exclusive remedy for our failure to deliver required volumes from such under such agreement, and no similar provision is contained in any of our other agreements with Enable.

In December 2015, we signed a 15-year gas gathering, processing, and purchase agreement with Enable under which we have dedicated the majority of our NW Stack acreage. We currently sell the residue and NGLs to Enable at market prices, with a contract option to take in-kind. Under the December 2015 Enable agreement, the dedicated area consists of approximately 236,000 gross acres of our NW Stack acreage.

December 2016 volumes of gas production dedicated to Enable under each of the March 2008 agreement, July 2011 agreement, January 2013 agreements and December 2015 agreement were 164,328 Mcf, 557,827 Mcf, 1,605,519 Mcf and 995,219 Mcf, respectively, which represent delivery to Enable of 100% of our total production for Verden, 98% of our total production for Stiles Ranch, and 80% of our total production for the NW Stack, all of which is subject to our contractual right to take the residue gas in-kind. These volumes are indicative of our current volume deliveries to Enable on a monthly basis.

Our Mocane-Laverne production is dedicated to, gathered, processed and purchased by DCP Midstream, L.P. under ten-year agreements, which commenced in December 2012. The majority of our Kansas gas production is dedicated to, gathered, processed and purchased by Targa Resources, LLC (“Targa”) under a five-year agreement, effective as of May 2014.

Plains Marketing currently purchases all of our oil production. Our Stiles Ranch, Verden, Mocane-Laverne and NW Stack production is dedicated and purchased under a five-year agreement that commenced in

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April 2015. This agreement contains a minimum volume commitment requiring us to deliver 4,000 Bb1/d, with shortfall payments of $1.55 per barrel (subject to annual escalation in accordance with the FERC Indexing Methodology due on a gross annual basis from April 1st through March 31st). Our Kansas production is covered by a separate three-year agreement with Plains Marketing, effective as of November 2015. There are no minimum volume commitments under this agreement.

We are currently party to a firm intrastate transportation service agreement (“FSTSA”) with Enable Oklahoma Intrastate Transmission, LLC for a portion of our natural gas production in Verden. The FSTSA runs for a primary term of 41 months, commenced in February 2015 and delivers into Natural Gas Pipeline Company of America. We continuously monitor the need to secure additional firm transportation contracts for incremental volumes from our Verden acreage but do not expect additional contracts in 2017.

Customers

We sell our oil, natural gas and NGLs production to customers at market prices. We sell our production to a relatively small number of customers, as is customary in our business. For the year ended December 31, 2016, three customers accounted for more than 10% of our revenue: Plains Marketing (42%), Enable (16%) and Spire (14%). For the year ended December 31, 2015, two customers accounted for more than 10% of our revenue: Plains Marketing (48%) and Spire (17%). For the year ended December 31, 2014, three customers accounted for more than 10% of our revenue: Plains Marketing (37%), Targa (35%) and Shell Trading (US) Company (24%). During such periods, no other customer accounted for 10% or more of our revenue. The loss of any of these customers could materially and adversely affect our revenues in the short-term. However, based on the current demand for oil and natural gas and the availability of other customers, we believe that the loss of any of our purchasers would not have a long-term material adverse effect on our financial condition and results of operations because crude oil and natural gas are fungible products with well-established markets.

Owned Infrastructure

In Stiles Ranch, we have a fee-based midstream system, which we refer to as “Wheeler Midstream,” consisting of low pressure natural gas gathering, intermediate/high pressure gas gathering, gas lift crude and liquids gathering and compression and storage for oil, water and NGLs located in Wheeler County, Texas. Our crude oil and NGL pipeline is subject to FERC jurisdiction, and although its rates are subject to regulation, it currently charges a contractual rate to third parties. Our acreage in Kansas is located along an established productive trend, and we have a saltwater disposal system (our “SWD System”) and related infrastructure in place that reduces our capital requirements and mitigates our saltwater disposal limitation risk.

Our infrastructure strategy includes utilizing Wheeler Midstream and our SWD System to continue to operate efficiently within the Stiles Ranch and Kansas, respectively. By keeping costs down in these locations, we can maximize cash flows directed towards our efforts in the NW Stack. Wheeler Midstream provides us with additional cash flow support with limited commodity price exposure.

With respect to Wheeler Midstream, we believe our ownership of this midstream infrastructure allows us to reduce our costs, promote overall efficiency of operations and increase our rates of return. Wheeler Midstream is an integrated pipeline gathering system that utilizes centralized compression, stabilization and tankage to support multi-pad drilling in 14 sections across the area. The gathering assets include 60 miles of low pressure gas gathering pipeline, 26 miles of intermediate/high pressure gas gathering pipeline, 24 miles of gas lift pipeline and 23 miles of crude and NGLs gathering pipeline. With respect to storage at Wheeler Midstream, we have 12 MBbls/d of oil capacity and 22 MBbls of storage, 30 MBbls/d of water capacity and 30 MBbls of storage and 90,000 gallons of NGLs storage. Wheeler Midstream has four gas driven compressor stations with an aggregate of 28,890 horsepower. The system was built to capture additional volumes in a high natural gas producing environment as well as additional third-party volumes, and currently has throughput capacity of over 126 MMcf/d.

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We believe our SWD System in Kansas provides us with a distinct competitive advantage. There are very few other operators leasing in Kansas, and we believe it is because prospective operators view it as uneconomical to develop an adequate saltwater disposal system, whereas we already have our SWD System in place. Our lease operating expenses in Kansas are very low, which we partially attribute to our SWD System.

We do not currently own or operate midstream infrastructure in the NW Stack, Verden or Mocane-Laverne and rely on third-party service providers to gather our production in those plays.

Competition

The oil and natural gas industry is intensely competitive, and we compete with other companies that have greater resources. Many of these companies not only explore for and produce oil and natural gas, but also carry on midstream and refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for productive oil and natural gas properties and exploratory prospects or to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. Our larger or more integrated competitors may be able to absorb the burden of existing, and any changes to, federal, state and local laws and regulations more easily than we can, which would 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 a highly competitive environment. In addition, because we have fewer financial and human resources than many companies in our industry, we may be at a disadvantage in bidding for exploratory prospects and producing oil and natural gas properties.

There is also competition between oil and natural gas producers and other industries producing energy and fuel. Furthermore, competitive conditions may be substantially affected by various forms of energy legislation and/or regulation considered from time to time by the governments of the United States and the jurisdictions in which we operate. It is not possible to predict the nature of any such legislation or regulation which may ultimately be adopted or its effects upon our future operations.

Such laws and regulations may substantially increase the costs of developing oil and natural gas and may prevent or delay the commencement or continuation of a given operation. Our larger competitors may be able to absorb the burden of existing, and any changes to, federal, state and local laws and regulations more easily than we can, which would adversely affect our competitive position.

Seasonality of Business

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

Title to Properties

As is customary in the oil and natural gas industry, we initially conduct only a cursory review of the title to our properties in connection with acquisition of leasehold acreage. At such time as we determine to conduct drilling operations on those properties, we conduct a thorough title examination and perform curative work with respect to significant defects prior to commencement of drilling operations. To the extent title opinions or other investigations reflect title defects on those properties, we are typically responsible for curing any title defects at our expense. We generally will not commence drilling operations on a property until we have cured any material title defects on such property. We have obtained title opinions on substantially all of our producing properties and believe that we have satisfactory title to our producing properties in accordance with standards generally accepted in the oil and natural gas industry.

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Prior to completing an acquisition of producing oil and natural gas leases, we perform title reviews on the most significant leases and, depending on the materiality of the underlying properties, we may obtain a title opinion, obtain an updated title review or opinion or review previously obtained title opinions. Our oil and natural gas properties are subject to customary royalty and other interests, liens for current taxes and other burdens which we believe do not materially interfere with the use of or affect our carrying value of the properties.

We believe that we have satisfactory title to all of our material assets. Although title to these properties is subject to encumbrances in some cases, such as customary interests generally retained in connection with the acquisition of real property, customary royalty interests and contract terms and restrictions, liens under operating agreements, liens related to environmental liabilities associated with historical operations, liens for current taxes and other burdens, easements, restrictions and minor encumbrances customary in the oil and natural gas industry, we believe that none of these liens, restrictions, easements, burdens and encumbrances will materially detract from the value of these properties or from our interest in these properties or materially interfere with our use of these properties in the operation of our business. In addition, we believe that we have obtained sufficient rights-of-way grants and permits from public authorities and private parties for us to operate our business in all material respects as described in this prospectus.

Oil and Natural Gas Leases

The typical oil and natural gas lease agreement covering our properties provides for the payment of royalties to the mineral owner for all oil and natural gas produced from any wells drilled on the leased premises. The lessor royalties and other leasehold burdens on our properties generally range from 12.50% to 25%, resulting in a net revenue interest to us generally ranging from 75% to 87.5%.

Regulation of the Oil and Natural Gas Industry

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

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

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

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Regulation of Production of Oil and Natural Gas

The production of oil and natural gas is subject to regulation under a wide range of local, state and federal statutes, rules, orders and regulations. Federal, state and local statutes and regulations require permits for drilling operations, drilling bonds and reports concerning operations. We own interests in properties located in Oklahoma, Texas and Kansas, each of which regulates drilling and operating activities by requiring, among other things, permits for the drilling of wells, maintaining bonding requirements in order to drill or operate wells, and regulating the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled and the plugging and abandonment of wells. The laws of each of Oklahoma, Texas and Kansas also govern a number of conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum allowable rates of production from oil and natural gas wells, the regulation of well spacing or density and plugging and abandonment of wells. The effect of these regulations is to limit the amount of oil and natural gas that we can produce from our wells and to limit the number of wells or the locations at which we can drill, although we can apply for exceptions to such regulations or to have reductions in well spacing or density. Moreover, each of Oklahoma, Texas and Kansas imposes a production or severance tax with respect to the production and sale of oil, natural gas and NGLs within its jurisdiction. We do not believe that we are impacted any differently by these regulations than similarly situated competitors.

The failure to comply with these rules and regulations can result in substantial penalties. Our competitors in the oil and natural gas industry are subject to the same regulatory requirements and restrictions that affect our operations.

Regulation of Oil Sales and Oil Pipelines

Sales of oil, condensate and NGLs are not currently regulated and are made at negotiated prices. Although prices of these energy commodities are currently unregulated, United States Congress could reenact price controls in the future. We cannot predict whether new legislation to regulate oil and NGLs, or the prices charged for these commodities might be proposed, what proposals, if any, might actually be enacted by the United States Congress or the various state legislatures and what effect, if any, the proposals might have on the our operations. Additionally, such sales may be subject to certain state, and potentially federal, reporting requirements.

Our sales of oil are affected by the availability, terms and cost of transportation. Prices received from the sale of oil liquids may be affected by the cost of transporting those products to market. Our crude oil and NGL pipeline is an interstate common carrier pipeline subject to regulation by the FERC under the Interstate Commerce Act (“ICA”), the Energy Policy Act of 1992 and related rules and orders. The ICA requires, among other things, that the tariff rates for common carrier oil pipelines be “just and reasonable” and must not be unduly discriminatory or confer any undue preference upon any shipper. FERC regulations require that such rates and terms and conditions of service be filed with the FERC.

The ICA permits interested persons to challenge proposed new or changed rates or rules and authorizes the FERC to investigate such changes and to suspend their effectiveness for a period of up to seven months. If, upon completion of an investigation, the FERC finds that the new or changed rate is unlawful, it may require the carrier to refund the revenues with interest in excess of the prior tariff during the term of the investigation. The FERC may also investigate, upon complaint or on its own motion, rates and related rules that are already in effect and may order a carrier to change them prospectively. Upon an appropriate showing, a shipper may obtain reparations for damages sustained for a period of up to two years prior to the filing of its complaint.

The rates for our interstate oil and NGL pipeline are charged based on a FERC-approved indexing methodology, which allows a pipeline to charge rates up to a prescribed ceiling that changes annually based on the change from year to year in the Producer Price Index for Finished Goods (“PPI”). A rate increase within the

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indexed rate ceiling is presumed to be just and reasonable unless a protesting party can demonstrate that the rate increase is substantially in excess of the pipeline’s costs. During the five-year period commencing July 1, 2016, crude oil and NGL pipelines charging indexed rates are permitted to adjust their indexed ceilings annually by the PPI plus 1.23%. The FERC’s order determining that pipelines charging indexed rates may adjust their indexed ceiling rates by PPI plus 1.23% is subject to ongoing judicial review. As an alternative to using the indexing methodogy, interstate crude oil and NGL pipelines rates may elect to support rates by using a cost of service methodology, by establishing settlement rates when agreed to by all affected shippers and by obtaining advance approval for market-based rates in certain circumstances. Shippers have the power to challenge new and existing rates and terms and conditions of service before FERC.

In October 2016, the FERC issued an advance notice of proposed rulemaking seeking comment regarding potential modifications to its policies for evaluating oil pipeline indexed rate changes and to the reporting requirements. The FERC observed that some pipelines continue to obtain additional index rate increases despite reporting on Form No. 6 that their revenues exceed their costs. The FERC is proposing a new policy that would deny proposed index increases if a pipeline’s Form No. 6 reflects that revenues exceed by fifteen percent total cost of service for both of the prior two years or the proposed index increases exceed by five percent the annual cost changes reported by the pipeline. In addition, in December 2016, the FERC issued a NOI in response to a remand from the U.S. Court of Appeals for the D.C. Circuit in United Airlines v. FERC, in which the court determined that FERC had not justified its conclusion that an oil pipeline organized as a partnership would not “double recover” its taxes under the current policy by both including a tax allowance in its cost-based rates and earning a return on equity calculated on a pre-tax basis. We cannot predict whether FERC will successfully justify its conclusion that there is no double recovery of taxes under these circumstances or whether FERC will modify its current policy on either income tax allowances or return on equity calculations.

Due to the complexity of ratemaking, the lawfulness of any rate is never assured. Prescribed rate methodologies for approving regulated tariff rates may limit our ability to set rates based on our actual costs or may delay the use of rates reflecting higher costs. Changes in the FERC’s methodology for approving rates could adversely affect us. In addition, challenges to our tariff rates could be filed with the FERC and decisions by the FERC in approving our rates could adversely affect our cash flow. We believe the transportation rates currently charged by our interstate common carrier crude oil and NGL pipeline are in accordance with the ICA. However, we cannot predict that rates we will be allowed to charge in the future for transportation services by our pipeline.

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

Regulation of Natural Gas Pipelines and Sales of Natural Gas

Historically, the transportation and sale for resale of natural gas in interstate commerce has been regulated by the FERC under the NGA, the NGPA and regulations and orders issued under those statutes. The regulation of pipeline transportation services and natural gas sales in interstate commerce by the FERC affects certain aspects of our business and the market for our products and services.

Among other matters, the EP Act of 2005 amended the NGA to add an anti-market manipulation provision. Pursuant to FERC’s rules promulgated under EP Act 2005, it is unlawful for any entity, directly or indirectly, in connection with the purchase or sale of natural gas subject to the jurisdiction of the FERC, or the purchase or sale of transportation services subject to FERC jurisdiction: (1) to use or employ any device, scheme or artifice to defraud; (2) to make any untrue statement of material fact or omit a material fact; or (3) to engage in any act or practice that operates as a fraud or deceit upon any person. EP Act 2005 also provided the FERC with

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substantial enforcement authority, including the power to assess civil penalties of up to $1,000,000 per day per violation, to order disgorgement of profits and to recommend criminal penalties. Effective August 1, 2016, to account for inflation, the maximum penalty increased to $1,973,970 per day. The anti-market manipulation rule and enhanced civil penalty authority reflect an expansion of FERC’s NGA enforcement authority.

Gathering service, which occurs upstream of jurisdictional transmission services, is regulated by the states onshore and in state waters. Section 1(b) of the NGA exempts natural gas gathering facilities from regulation by FERC under the NGA. The distinction between FERC-regulated transmission

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