Goldman sachs leveraged finance conference final v2

GOLDMAN SACHS LEVERAGED FINANCE CONFERENCE

May 17, 2016

2Goldman Sach - Leveraged Finance Conference

FORWARD-LOOKING STATEMENTS

• This presentation includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Forward-looking statements are statements other than statements of historical fact. They include statements that give our current expectations or forecasts of future events, production and well connection forecasts, estimates of operating costs, planned development drilling and expected drilling cost reductions, capital expenditures, expected efficiency gains, our ability to improve margins, reduce operating and G&A expenses, optimize base production, the timing of anticipated asset sales and proceeds to be received therefrom, projected cash flow and liquidity, business strategy and other opportunities, plans and objectives for future operations (including restructuring of midstream gathering agreements), and the assumptions on which such statements are based. Although we believe the expectations and forecasts reflected in the forward-looking statements are reasonable, we can give no assurance they will prove to have been correct. They can be affected by inaccurate or changed assumptions or by known or unknown risks and uncertainties.

• Factors that could cause actual results to differ materially from expected results include those described under “Risk Factors” in Item 1A of our annual report on Form 10-K and any updates to those factors set forth in Chesapeake's subsequent quarterly reports on Form 10-Q or current reports on Form 8-K (available at http://www.chk.com/investors/sec-filings). These risk factors include the volatility of oil, natural gas and NGL prices; the limitations our level of indebtedness may have on our financial flexibility; our inability to access the capital markets on favorable terms or at all; the availability of cash flows from operations and other funds to finance reserve replacement costs or satisfy our debt obligations; a further downgrade in our credit rating requiring us to post more collateral under certain commercial arrangements; write-downs of our oil and natural gas asset carrying values due low commodity prices; our ability to replace reserves and sustain production; uncertainties inherent in estimating quantities of oil, natural gas and NGL reserves and projecting future rates of production and the amount and timing of development expenditures; our ability to generate profits or achieve targeted results in drilling and well operations; leasehold terms expiring before production can be established; commodity derivative activities resulting in lower prices realized on oil, natural gas and NGL sales; the need to secure derivative liabilities and the inability of counterparties to satisfy their obligations; adverse developments or losses from pending or future litigation and regulatory proceedings, including royalty claims; charges incurred in response to market conditions and in connection with our ongoing actions to reduce financial leverage and complexity; drilling and operating risks and resulting liabilities; effects of environmental protection laws and regulation on our business; legislative and regulatory initiatives further regulating hydraulic fracturing; our need to secure adequate supplies of water for our drilling operations and to dispose of or recycle the water used; impacts of potential legislative and regulatory actions addressing climate change; federal and state tax proposals affecting our industry; potential OTC derivatives regulation limiting our ability to hedge against commodity price fluctuations; competition in the oil and gas exploration and production industry; a deterioration in general economic, business or industry conditions; negative public perceptions of our industry; limited control over properties we do not operate; pipeline and gathering system capacity constraints and transportation interruptions; terrorist activities and cyber-attacks adversely impacting our operations; potential challenges of our spin-off of Seventy Seven Energy Inc. (SSE) in the event of a bankruptcy of SSE; an interruption in operations at our headquarters due to a catastrophic event; the continuation of suspended dividend payments on our common stock and preferred stock; certain anti-takeover provisions that affect shareholder rights; and our inability to increase or maintain our liquidity through debt repurchases, capital exchanges, asset sales, joint ventures, farmouts or other means.

• In addition, disclosures concerning the estimated contribution of derivative contracts to our future results of operations are based upon market information as of a specific date. These market prices are subject to significant volatility. Our production forecasts are also dependent upon many assumptions, including estimates of production decline rates from existing wells and the outcome of future drilling activity. Expected asset sales may not be completed in the time frame anticipated or at all. We caution you not to place undue reliance on our forward-looking statements, which speak only as of the date of this presentation, and we undertake no obligation to update any of the information provided in this presentation, except as required by applicable law.

Goldman Sach - Leveraged Finance Conference 3

2016 KEY ACHIEVEMENTS TO DATE

• ~$1.2 billion in asset divestitures closed or under signed PSA > Up from $700mm announced in February> Reiterating target of $1.2 – $1.7 billion in asset divestitures in 2016

• Amended revolving credit facility covenants and reaffirmed $4 billion borrowing base capacity

• Reduced 2017 maturing / puttable debt by ~$700 million a 32% reduction since 9/30/15; $410mm YTD as of 5/11/16

• Cash costs down 28% in first quarter YOY (1)(1) Includes production expenses and general and administrative expenses, including stock based compensation.


CHESAPEAKE’S FOCUS IN 2016WHAT WE PLAN TO DO

(1) Includes production expenses and general and administrative expenses, including stock based compensation.

2016 Plan 2016 Progress to Date

Maximize Liquidity

□ Reduce capital budget by >50%□ 10% reduction in LOE/boe□ 15% reduction in G&A/boe (1)

■ On track to reduce capital budget by >50% YOY

■ Reduced cash costs by 28% first quarter YOY (1)

Optimize Portfolio

□ Close on $700mm in signed asset divestitures□ $500 – $1,000mm in additional asset

divestitures□ Fund short-cycle cash-generating projects

■ $1.2 billion in total asset divestitures closed or under PSA YTD

■ Reiterating target of $1.2 – $1.7 billion in asset divestitures in 2016

Increase EBITDA

□ Improve gathering and transportation agreements

□ 2016 capital program focusing on TILS□ Reduce base decline rate by 10%

■ Continued progress on contract renegotiations

■ >50% of D&C capital allocated for inventory drawdown

Debt Management/Elimination

□ Proactive liability management□ Open market repurchases of debt□ Focus on 2017 and 2018 maturity

management

■ Reduced 2017 maturing/puttable debt by ~$700mm, a 32% reduction since 9/30/15; $410mm YTD as of 5/11/16


(1) Approximately $950 million in net proceeds after VPP obligations are met.(2) Production from signed or closed divestitures is approximately 60% gas, 20% oil, and 20% NGL.

SIGNIFICANT PROGRESS ON ASSET DIVESTITURE GOAL

~$1.2 billionExpected gross proceeds from 2016 signed or closed divestitures (1)

~35 mboe/dMinimal impact to 2016 production volumes (60% gas) (2)

$45 millionMinimal 2016 projected EBITDA impact

$1.2 - $1.7 billionTargeted asset divestitures by YE 2016


1Q'16 2Q'16E 3Q'16E 4Q'16E

$20

$40

$20 $20

Budgeted 2016 STACK D&C CAPEX

• Partial Meramec monetization for $470mm accelerates significant value for shareholders

• Maintaining a substantial position after 2016 divestitures˃ 52,000 acres remain in STACK corridor

˃ 1.5mm acres remain in the Mid-Continent

• ~$100mm in capital available to redirect to other investment opportunities

• Borrowing base not impacted by Meramec monetization

MERAMEC VALUE ACCELERATION

Effective Date: 4/1/16


CAPITAL DISCIPLINE REMAINS FOCUS

• On track for >50% reduction in total capex vs. 2015˃ Capex down 75% in first quarter YOY

• Majority of 2016 projected capex focused on DUC inventory drawdown

(1) Includes D&C costs, leasehold, G&G, other PP&E and capitalized interest.(2) Unadjusted for asset sales.

1Q 2Q 3Q 4Q0

200

400

600

800

Production (2)

2015 2016E

Prod

ucito

n (m

boe/

d)

1Q 2Q 3Q 4Q$0

$400

$800

$1,200

$1,600

Capital Spending (1)

2015 2016E

Quar

terly

Cap

Ex S

pend

($m

m)


CONTINUOUS IMPROVEMENT OF CASH COSTS

• Plan to reduce G&A by 15% and LOE by 10% in 2016

• Progress being made on both fronts in early 2016> 28% reduction in cash costs

in first quarter YOY (1)

> ~$100mm reduction in cash costs YOY (1)

• History of continuous cash cost improvement

2012 2013 2014 2015 2016 E

$7.76$6.60

$5.93$5.17

Annual Cash Costs ($/boe)

$4.10 – $4.50 (2)

(1)

(1)

1Q'15 2Q'15 3Q'15 4Q'15 1Q'16

$5.75 $5.40$4.87 $4.64 $4.14

Quarterly Cash Costs ($/boe)

(1) Includes production expenses and general and administrative expenses, including stock based compensation.(2) Guidance as of May 5, 2016.

Goldman Sach - Leveraged Finance Conference

Marcellus Shale144 mboe/d net (1)

Spud: 0-5 / TIL: 20Utica Shale (2)

146 mboe/d net (1)

Spud: 0-5 / TIL: 45-55

Barnett Shale69 mboe/d net (1)

Spud: 0 / TIL: 5

Eagle Ford Shale91 mboe/d net (1)

Spud: 20-30 / TIL: 170-180

Powder River Basin17 mboe/d net (1)

Spud: 0 / TIL: 5

Mid-Continent93 mboe/d net (1)

Spud: 30-40 / TIL: 25-35

Haynesville Shale112 mboe/d net (1)

Spud: 25-35 / TIL: 50-60

VAST U.S. ONSHORE ASSET PORTFOLIOSIGNIFICANT VALUE IN DEVELOPED AND UNDEVELOPED ACREAGE

9

~8.0mm net acres in developed and undeveloped leasehold (3)

(1) Average daily production 1Q’16.(2) Includes production volumes from legacy Devonian wells in West Virginia and Kentucky.(3) Estimated as of 3/31/2016.


CONTINUOUS IMPROVEMENT IN CAPITAL EFFICIENCY

(1) Data represents average net D&C $ / net EUR in boe, grouped by TIL year.

2012 2013 2014 2015 2016 E

$19

$13

$7 $6

Haynesville Shale

68%

2012 2013 2014 2015

$22$18

$14 $14

Mid-Continent

37%

2012 2013 2014 2015 2016 E

$26$21

$15 $17

Eagle Ford Shale

34%

2012 2013 2014 2015

$9$8

$6 $5

Marcellus Shale

47%

2012 2013 2014 2015

$18

$10 $9 $8

Utica Shale

56%

Continually improved F&D cost across the portfolio

(1)

Significant improvements forecasted for 2016

0 50 100 150 200 250 300 350 4000

2

4

6

8

10

12 Longer Lateral Productivity

Legacy Wells: ~4,400' LL 10,000' LL Wells Time (Days)

Cum

ulat

ive

Gas (

MM

cf)

2013 2014 2015 2016E4,000

5,000

6,000

7,000

8,000

9,000Lateral Length Progression

HAYNESVILLE SHALELONGER LATERALS DRIVING EFFICIENCY


• 23% decrease in projected D&C costs in 2016 vs. 2015

• Long laterals provide 63% increase in 160-day cumulative gas production˃ Efficiency gains driving ROR

higher

• ~8,000’ average lateral length in 2016

63% Increase

75% Longer laterals projected to be drilled in 2016E vs. 2013

Drille

d La

tera

l Len

gth

(ft.)

(1) Legacy wells includes 27 wells with in-unit laterals. 10,000 LL includes three wells traversing two sections with down time removed.

(1)


EAGLE FORD SHALECAPITAL EFFICIENCY DRIVING COMPETITIVE RETURNS

• Outstanding well performance to date for extended lateral program

• Per foot development costs reduced by ~50%

• Current returns on development program at $45/bbl oil outcompete 2014 program at $80/bbl oil (1)

0 10 20 30 40 50 60 70 80 90 1000

1020304050 Cumulative Oil Production

XL Pad - Avg. LL 9,900'Control Avg. LL 4,983'

Days

Cum

ulat

ive

Oil (

Mbo)

(1) Pricing assumptions: 2016: $47.32/$2.52, 2017: $49.00/$3.01, 2018: $50.22/$3.04, 2019: $51.35/$3.04, 2020+: $53/$3.25

2014 YE

2015 Avg.

2016 1QE 2016 2QE YE Goal

4,0006,0008,000

10,00012,000

5,600 6,500 6,500

9,00010,500

Lateral Length

Late

ral L

engt

h (ft

.)2014 YE

2015 Avg.

2016 1QE 2016 2QE YE Goal

$0

$500

$1,000

$1,500$1,000 $923

$600 $522 $429

Cost per Foot

Dolla

rs p

er Fo

ot

25 - 50%Expected ROR for 2016 development program (1)

13

Second lien debt exchange

Announced $700mm in noncore asset divestitures

Announced $500mm in asset divestitures; Amended credit facility

Continue maximizing liquidity, increasing EBITDA and reducing debt

THE TRANSFORMATION CONTINUES

Maximize Liquidity: 2016 capital spend is down more than ~50%

Optimize Portfolio: $1.2 billion in asset divestitures signed YTD

Increase EBITDA: Reduce costs and work to restructure contracts

Debt Management/Elimination: ~$700 million reduction in 2017 debt (1)


4Q 1Q 2Q 3Q 4Q2015 2016

(1) Since 9/30/2015, as of 5/11/16.

14

APPENDIX



REVOLVER CREDIT FACILITY AMENDMENT

•Revolving credit facility capacity affirmed at $4 billion•Facility will not be subject to another redetermination until June 2017•Senior secured leverage ratio suspended through September 2017˃ Resuming at 3.5x thereafter through December 2017 and decreasing to

3.0x thereafter

• Interest coverage ratio covenant was reduced to 0.65x from 1.1x through March 2017 > After which it will increase to 0.70x through June 2017, then reverting to

1.2x in September 2017 and to 1.25x thereafter Amendments to revolver provides significant liquidity and optionality in 2016 for Chesapeake


32% REDUCTION IN 2017 MATURING/PUTTABLE DEBT

9/30/15 Outstanding 5/11/16 Outstanding$0

$500

$1,000

$1,500

$2,000

$2,500

$392 $344

$660

$342

$1,168

$812

6.25% 2017 6.5% 2017 2.5% 2037

$ MM

(1) 6.25% 2017's converted to USD for entire period using exchange rate of $1.1426 to €1.00 as of 5/11/16.(2) Incremental liquidity savings includes principal savings and net interest impact.

$2,220

$1,498 (1) ~$620mm Total incremental liquidity since 9/30/2015 through proactive liability management (2)

Financial Transaction Liquidity Savings

Debt Exchange

$305mm of new 2nd lien $291mm

Open Market Repurchases $99mm of cash $86mm

Equity for Debt

Exchanges42.3mm shares

(valued at $193mm) $240mm

From 9/30/2015 through 5/11/2016, reduced 2017 maturing/puttable debt obligations by

~$700mm


$1,498

$868

$1,089 $1,126

$876

$639

$384

$2,425

$723

$147

$411

$674$824

$861

$716

2017 2018 2019 2020 2021 2022 2023

(1) Recognizes earliest investor put option as maturity for the 2.50% 2037 and 2.25% 2038 Contingent Convertible Senior Notes.(2) Euro-notes are converted to USD using exchange rate of $1.1426 to €1.00 (5/11/16).

MATURITY PROFILEPROACTIVE LIABILITY MANAGEMENT

Debt Reduction

Unsecured Notes(1)

2nd Lien Notes

Market Value(2)

(2)

$67.0 millionAnnual interest payment reduction from all liability management transactions

$2.8 billion Debt principal removed from books in 2015 and 2016 as of 3/13/16


CREDIT COLLATERAL SUPPORT

(1) Excluding the supersedeas bond with respect to the 6.775% Senior Notes due 2019 litigation.

Posted - Midstream

Posted - Hedging Posted - Others Potential – Midstream and Insurance

12/31/2015 2/24/2016 3/31/2016 5/3/2016$0

$50

$100

$150

$200

$250

$300

$350

$400

$0

$200

$400

$600

$800

$1,000

$4 $47

$133 $111

$5

$34

$57 $104

$11

$11

$32 $32

$1,097

$826 $733 $730

Milli

ons U

SD (1

)

Milli

ons U

SD

Midstream collateral requirements decreasing while hedging counterparty requirements increased due to higher commodity prices


HEDGING POSITION (1)

(1) For April - December 2016 production as of May 3, 2016.

Swaps $2.71/mcf Swaps $46.32/bbl

73 bcf of 2017 gas volumes hedged with swaps @ $2.922.9 mmbbl of 2017 oil volumes hedged with swaps @ $42.53

Ethane Swaps $0.17/galPropane Swaps $0.46/gal

64%

Natural Gas (1)2016

69%

38%

Natural Gas2016

Oil2016

NGL2016


CORPORATE INFORMATION

PUBLICLY TRADED SECURITIES CUSIP TICKER6.25% Senior Notes due 2017 #027393390 N/A6.50% Senior Notes due 2017 #165167BS5 CHK177.25% Senior Notes due 2018 #165167CC9 CHK18A3mL + 3.25% Senior Notes due 2019 #165167CM7 CHK196.625% Senior Notes due 2020 #165167CF2 CHK20A6.875% Senior Notes due 2020 #165167BU0 CHK206.125% Senior Notes Due 2021 #165167CG0 CHK215.375% Senior Notes Due 2021 #165167CK21 CHK21A8.00% Senior Secured Second Lien Notes due 2022 #165167CQ8

#U16450AT2N/AN/A

4.875% Senior Notes Due 2022 #165167CN5 CHK225.75% Senior Notes Due 2023 #165167CL9 CHK232.75% Contingent Convertible Senior Notes due 2035 #165167BW6 CHK352.50% Contingent Convertible Senior Notes due 2037 #165167BZ9/

#165167CA3CHK37/ CHK37A

2.25% Contingent Convertible Senior Notes due 2038 #165167CB1 CHK384.5% Cumulative Convertible Preferred Stock #165167842 CHK PrD 5.0% Cumulative Convertible Preferred Stock (Series 2005B)

#165167834/#165167826 N/A

5.75% Cumulative Convertible Preferred Stock#U16450204/#165167776/#165167768

N/A

5.75% Cumulative Convertible Preferred Stock (Series A)#U16450113/#165167784/ #165167750

N/A

Chesapeake Common Stock #165167107 CHK

HEADQUARTERS

6100 N. Western AvenueOklahoma City, OK 73118WEBSITE: www.chk.com

CORPORATE CONTACTS

BRAD SYLVESTER, CFAVice President – Investor Relations and Communications

DOMENIC J. DELL’OSSO, JR. Executive Vice President and Chief Financial Officer

Investor Relations department can be reached at [email protected]

http://www.chk.com/

mailto:[email protected]

Goldman sachs leveraged finance conference final v2

Investor Relations

Transcript of Goldman sachs leveraged finance conference final v2